MDU Resources (NYSE: MDU) outlines regulated utility and pipeline focus

Rhea-AI Filing Summary

MDU Resources Group, Inc. files its Form 10-K describing its transformation into a pure-play regulated energy delivery company. It now focuses on three segments: electric, natural gas distribution and pipeline, all operating under state commissions and FERC oversight.

The company completed the separations of Knife River in 2023 and Everus in 2024, leaving a fully regulated profile. It serves about 146,550 electric customers and over 1.08 million natural gas customers, and owns a FERC-regulated pipeline with extensive storage capacity.

Key themes include heavy regulation of rates and returns, use of riders and trackers to reduce regulatory lag, growing exposure to data-center and RNG demand, and detailed disclosure of environmental, wildfire, weather, cybersecurity, capital market and aging-infrastructure risks that could affect future costs and earnings.

Insights

Regulated utility and infrastructure analyst

MDU is now a focused regulated utility with standard but wide-ranging risk pressures.

MDU Resources highlights its shift to a pure-play regulated model after spinning off Knife River in 2023 and Everus in 2024. Earnings will now depend mainly on its electric, natural gas distribution and pipeline rate bases, subject to multi-state commission and FERC oversight.

The filing emphasizes mechanisms such as fuel and power cost trackers, renewable and transmission riders, and decoupling in certain gas jurisdictions. These tools can temper regulatory lag, but outcomes still hinge on prudence findings, franchise renewals, and treatment of future asset retirements, including coal-fired generation and aging infrastructure.

Risk disclosure is extensive: climate and severe weather, wildfire liability, environmental compliance, supply chain constraints, and capital market access all feature prominently. The pipeline segment depends on long-term contracts and storage value, while data-center and RNG-related loads could be incremental growth drivers, with actual impact determined by future regulatory and customer decisions.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ______________

Commission file number 1-03480

MDU RESOURCES GROUP, INC.

(Exact name of registrant as specified in its charter)

Delaware						30-1133956
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

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, par value $1.00 per share			MDU			New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer			☒			Accelerated filer			☐
Non-accelerated filer			☐			Smaller reporting company			☐
						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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒.

State the aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2025: $3,394,621,007.

Indicate the number of shares outstanding of the registrant's common stock, as of February 13, 2026: 204,382,821 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Relevant portions of the registrant's 2026 Proxy Statement, to be filed no later than 120 days from December 31, 2025, are incorporated by reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.

Contents

Part I						Page
Definitions						4
Cautionary Note Regarding Forward-Looking Statements						7
Item 1			Business			7
			General			7
			Electric			12
			Natural Gas Distribution			17
			Pipeline			20
			Discontinued Operations			21
Item 1A			Risk Factors			21
Item 1B			Unresolved Staff Comments			34
Item 1C			Cybersecurity			34
Item 2			Properties			36
Item 3			Legal Proceedings			36
Item 4			Mine Safety Disclosures			36
Part II
Item 5			Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			37
Item 6			Reserved			37
Item 7			Management's Discussion and Analysis of Financial Condition and Results of Operations			38
Item 7A			Quantitative and Qualitative Disclosures About Market Risk			62
Item 8			Financial Statements and Supplementary Data			63
			Consolidated Statements of Income			67
			Consolidated Statements of Comprehensive Income			68
			Consolidated Balance Sheets			69
			Consolidated Statements of Equity			70
			Consolidated Statements of Cash Flows			71
			Notes to Consolidated Financial Statements			73
			1. Basis of Presentation			73
			2. Significant Accounting Policies			74
			3. Discontinued Operations			80
			4. Revenue from Contracts with Customers			81
			5. Property, Plant and Equipment			83
			6. Regulatory Matters			84
			7. Environmental Allowances and Obligations			86
			8. Fair Value Measurements			87
			9. Debt			89
			10. Asset Retirement Obligations			91
			11. Equity			92
			12. Stock-Based Compensation			93

2 MDU Resources Group, Inc. Form 10-K

Contents

Part II (continued)						Page
			13. Income Taxes			95
			14. Business Segment Data			98
			15. Employee Benefit Plans			102
			16. Jointly Owned Facilities			110
			17. Commitments and Contingencies			111
Item 9			Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			115
Item 9A			Controls and Procedures			115
Item 9B			Other Information			115
Item 9C			Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			115
Part III
Item 10			Directors, Executive Officers, and Corporate Governance			116
Item 11			Executive Compensation			116
Item 12			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			116
Item 13			Certain Relationships and Related Transactions, and Director Independence			116
Item 14			Principal Accountant Fees and Services			116
Part IV
Item 15			Exhibits, Financial Statement Schedules			117
3. Exhibits						122
Item 16			Form 10-K Summary			124
Signatures						125

MDU Resources Group, Inc. Form 10-K 3

Definitions

The following abbreviations and acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym
AFUDC			Allowance for funds used during construction
Applied Digital			Applied Digital Corporation
Army Corps			U.S. Army Corps of Engineers
ASC			FASB Accounting Standards Codification
ASU			FASB Accounting Standards Update
ATM			At-the-Market
Badger Wind Farm			250 MW wind turbine farm near Wishek, North Dakota (49.0 percent ownership)
Bcf			Billion cubic feet
Big Stone Station			475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
Board			Company's Board of Directors
BSSE			345-kV transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota (50 percent ownership)
Cascade			Cascade Natural Gas Corporation, an indirect wholly-owned subsidiary of MDU Energy Capital
Centennial			CEHI, LLC, a direct wholly-owned subsidiary of the Company, formerly known as Centennial Energy Holdings, Inc. prior to the separation of Knife River from the Company. References to Centennial's historical business and operations refer to the business and operations of Centennial Energy Holdings, Inc.
Centennial Capital			Centennial Holdings Capital LLC, a direct wholly-owned subsidiary of Centennial
CERCLA			Comprehensive Environmental Response, Compensation and Liability Act
CIO			Chief Information Officer
Code			U.S. Internal Revenue Code
CODM			Chief Operating Decision Maker
Company			MDU Resources Group, Inc.
COVID-19			Coronavirus disease 2019
Coyote Creek			Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station			427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
CWIP			Construction work in progress, costs associated with the construction of new utility facilities recorded on the balance sheet until these facilities are placed in service.
CyROC			Cyber Risk Oversight Committee
DC Circuit Court			U.S Court of Appeals for the D.C. Circuit
dk			Decatherm
EBITDA			Earnings before interest, taxes, depreciation and amortization
EIN			Employer Identification Number
EDA			Equity Distribution Agreement
EPA			U.S. Environmental Protection Agency
ERISA			Employee Retirement Income Security Act of 1974, as amended
ERM			Enterprise risk management
ESG			Environmental, social and governance
Everus			Everus Construction Group, Inc., a wholly-owned subsidiary of the Company prior to the separation from the Company, that was established in conjunction with the separation of Everus Construction
Everus Construction			Everus Construction, Inc., a direct wholly-owned subsidiary of Centennial prior to the separation from the Company, formerly known as MDU Construction Services Group, Inc. prior to March 12, 2024
Exchange Act			Securities Exchange Act of 1934, as amended
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission

4 MDU Resources Group, Inc. Form 10-K

Definitions

Fidelity			Fidelity Exploration & Production Company, an indirect wholly-owned subsidiary of Centennial (previously referred to as the Company's exploration and production segment)
FIP			Funding improvement plan
FSA			Forward sale agreement
GAAP			Accounting principles generally accepted in the United States of America
GHG			Greenhouse gas
Great Plains			Great Plains Natural Gas Co., a public utility division of Montana-Dakota
GVTC			Generation Verification Test Capacity
Holding Company Reorganization			The internal holding company reorganization completed on January 1, 2019, pursuant to the agreement and plan of merger, dated as of December 31, 2018, by and among Montana-Dakota, the Company and MDUR Newco Sub, which resulted in the Company becoming a holding company and owning all of the outstanding capital stock of Montana-Dakota.
IBEW			International Brotherhood of Electrical Workers
ICWU			International Chemical Workers Union
Impact Report			Company's 2024 Impact Report
Intermountain			Intermountain Gas Company, an indirect wholly-owned subsidiary of MDU Energy Capital
IPUC			Idaho Public Utilities Commission
IRA			Inflation Reduction Act
IRP			Integrated Resource Plan
IRS			Internal Revenue Service
Item 8			Financial Statements and Supplementary Data
JETx			345-kV transmission line from Jamestown, North Dakota to Ellendale, North Dakota (50 percent ownership)
Knife River			Established as Knife River Corporation prior to the separation from the Company, a direct wholly-owned subsidiary of Centennial. Knife River refers to Knife River Corporation, during the period prior to separation, now known as "KRC Materials, Inc." Following the separation Knife River refers to Knife River Holding Company, now known as Knife River Corporation.
K-Plan			Company's 401(k) Retirement Plan
kW			Kilowatts
kWh			Kilowatt-hour
kV			Kilovolts
Leading with Integrity Policy			Company's code of business conduct
MAOP			Maximum allowable operating pressure
MD&A			Management's Discussion and Analysis of Financial Condition and Results of Operations
MDU Energy Capital			MDU Energy Capital, LLC, a direct wholly-owned subsidiary of the Company
MDUR Newco			MDUR Newco, Inc., a public holding company created by implementing the Holding Company Reorganization, now known as the Company
MDUR Newco Sub			MDUR Newco Sub, Inc., a direct, wholly-owned subsidiary of MDUR Newco, which was merged with and into Montana-Dakota in the Holding Company Reorganization
MEPP			Multiemployer pension plan
MISO			Midcontinent Independent System Operator, Inc., the organization that provides open-access transmission services and monitors the high-voltage transmission system in the Midwest United States and Manitoba, Canada and a southern United States region which includes much of Arkansas, Mississippi and Louisiana
MMcf			Million cubic feet
MMdk			Million dk
MNPUC			Minnesota Public Utilities Commission
Montana-Dakota			Montana-Dakota Utilities Co. a direct wholly-owned subsidiary of MDU Energy Capital
MPPAA			Multiemployer Pension Plan Amendments Act of 1980
MTPSC			Montana Public Service Commission
MW			Megawatt
NDDEQ			North Dakota Department of Environmental Quality

MDU Resources Group, Inc. Form 10-K 5

Definitions

NDPSC			North Dakota Public Service Commission
NERC			North American Electric Reliability Corporation
NPA			Note Purchase Agreement
NYSE			New York Stock Exchange
OBBBA			One Big Beautiful Bill Act
ODEQ			Oregon Department of Environmental Quality
OPUC			Oregon Public Utility Commission
PCAOB			Public Company Accounting Oversight Board
PCBs			Polychlorinated biphenyls
PHMSA			Pipeline and Hazardous Material Safety Administration
PPA			Power purchase agreement
Proxy Statement			Company's 2026 Proxy Statement
PRP			Potentially Responsible Party
PSAs			Performance share awards
RCRA			Resource Conservation and Recovery Act
RNG			Renewable natural gas
ROE			Return on equity
RP			Rehabilitation plan
RSUs			Restricted stock units
SBCC			State Building Code Council
SDPUC			South Dakota Public Utilities Commission
SEC			U.S. Securities and Exchange Commission
Securities Act			Securities Act of 1933, as amended
Sheridan System			A separate electric system owned by Montana-Dakota
SOFR			Secured Overnight Financing Rate
SPP			Southwest Power Pool, the organization that manages the electric grid and wholesale power market for the central United States.
TSA			Transportation Security Administration
UA			United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
VIE			Variable interest entity
Washington DOE			Washington State Department of Ecology
WBI Energy			WBI Energy, Inc., an indirect wholly-owned subsidiary of Centennial
WBI Energy Transmission			WBI Energy Transmission, Inc., an indirect wholly-owned subsidiary of Centennial
WUTC			Washington Utilities and Transportation Commission
Wygen III			100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYPSC			Wyoming Public Service Commission
ZRCs			Zonal resource credits - a MW of demand equivalent assigned to generators by MISO for meeting system reliability requirements

6 MDU Resources Group, Inc. Form 10-K

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Cautionary Note Regarding Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of the federal securities laws. Other than statements of historical facts, all statements which address activities, events or developments that the Company anticipates will or may occur in the future are based on underlying assumptions (many of which are based, in turn, upon further assumptions), including, but not limited to, statements identified by the words "anticipates," "estimates," "expects," "intends," "plans," and "predicts," in each case related to such things as growth estimates, stockholder value creation, the Company's "CORE" strategy, capital expenditures, financial guidance, trends, objectives, goals, strategies, earnings per share growth targets, dividend payout ratio targets, customer rates, regulatory approvals, sustainability, and other such matters, each of which is a forward-looking statement. These forward-looking statements are based on many assumptions and factors, which are detailed in the Company's filings with the SEC.

While made in good faith, these forward-looking statements are based largely on the Company's expectations and judgments and are subject to a number of risks and uncertainties, many of which are unforeseeable and beyond the Company's control. For additional discussion regarding risks and uncertainties that may affect forward-looking statements, see Item 1A - Risk Factors. Any changes in such assumptions or factors could produce significantly different results. Undue reliance should not be placed on forward-looking statements, which speak only as of the date they are made. Except as required by applicable law, the Company undertakes no obligation to update the forward-looking statements, whether as a result of new information, future events or otherwise.

Item 1. Business

General

The Company is a pure-play regulated energy delivery business. Its principal executive offices are located at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota was incorporated under the state laws of Delaware in 1924. The Company was incorporated under the state laws of Delaware in 2018. Upon the completion of the Holding Company Reorganization, Montana-Dakota became a subsidiary of the Company. The Company adopted a new mission statement in early 2025, "With integrity, deliver value as a leading energy provider and employer of choice."

Through a strategy focusing on its "CORE," the Company strives to deliver superior value and achieve industry-leading performance as a pure-play regulated energy delivery company, while pursuing organic growth opportunities. The Company's "CORE" strategy prioritizes customers and communities, operational excellence, returns focused initiatives and an employee driven culture. The Company generates, transmits and distributes electricity and provides natural gas distribution, transportation and storage services. These businesses are regulated by state public service commissions and/or the FERC.

As part of the Company's continual review of its business, the Company announced strategic initiatives to enhance stockholder value. On May 31, 2023, the Company executed the separation of Knife River, the construction materials and contracting business, from the Company, resulting in Knife River becoming an independent, publicly-traded company. On October 31, 2024, the Company completed the separation of Everus, the construction services business, from the Company, resulting in Everus becoming an independent, publicly-traded company.

MDU Resources Group, Inc. Form 10-K 7

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As of December 31, 2025, the Company was organized into three reportable business segments. These business segments include: electric, natural gas distribution and pipeline. The Company's business segments are determined based on the Company's method of internal reporting, which generally segregates the business activities by differences in products and services. The internal reporting of these segments is defined based on the reporting and review process used by the Company's chief executive officer.

The Company, through its wholly-owned subsidiary, MDU Energy Capital, owns Montana-Dakota, Cascade and Intermountain. The electric segment is comprised of Montana-Dakota while the natural gas distribution segment is comprised of Montana-Dakota, Cascade and Intermountain.

The Company, through its wholly-owned subsidiary, Centennial, owns WBI Energy and Centennial Capital. WBI Energy is the pipeline segment and Centennial Capital is reflected in the Other category.

The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth in Item 7 - MD&A and Item 8 - Note 14.

The Company's material properties, which are of varying ages and are of different construction types, are generally in good condition, are well maintained and are generally suitable and adequate for the purposes for which they are used.

Human Capital Management An employee driven culture is part of the Company's "CORE" strategy, which means striving to be an employer of choice. It begins with employee feedback on continuous improvement and fosters an inclusive and respectful culture. It also includes driving employee safety through proactive safety management systems. As of December 31, 2025, the Company had 2,096 employees.

Many of the Company's employees are represented by collective-bargaining agreements and the Company is committed to establishing constructive dialogue with this representation and bargaining in good faith. The majority of the collective-bargaining agreements contain provisions that prohibit work stoppages or strikes and provide dispute resolution through binding arbitration in the event of an extended disagreement.

The following information about the Company's collective-bargaining agreements is as of December 31, 2025.

Company			Collective-bargaining agreement			Number of employees represented			Agreement status
Montana-Dakota			IBEW			323			Effective through April 30, 2026
Intermountain			UA			167			Three agreements effective through October 31, 2026, January 31, 2027, and January 31, 2027.
Cascade			ICWU			179			Effective through March 31, 2028
WBI Energy Transmission			IBEW			76			Effective through April 30, 2027
Total						745

8 MDU Resources Group, Inc. Form 10-K

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Respectful Workplace The Company is committed to an environment that respects the differences and embraces the strengths of its employees. Essential to the Company's success is its ability to attract, retain and engage the best people from a broad range of backgrounds and build an inclusive culture where all employees feel valued and contribute their best. The Company requires employees to participate in its Leading with Integrity Policy which provides training on the Company's code of conduct.

The Company's goals related to a respectful workplace include:

•Enhance collaboration efforts through cooperation and sharing of best practices to create new ways of meeting employee, customer and stockholder needs.

•Increase productivity and profitability through the creation of a work environment which values all perspectives and methods of accomplishing work.

The Company also promotes recognition of employees through the following awards:

Building People Being employee driven begins with employee recruitment. The Company hires employees that have the skills, abilities and motivation to achieve the results needed for their jobs. Each job is important and part of a coordinated team effort to accomplish the organization's objectives. The Company uses a variety of means to recruit new employees for open positions including posting on the Company's website. Other sources for employee recruitment include employee referrals, union workforce, direct recruitment, advertising, social media, career fairs, partnerships with colleges and technical schools, job service organizations and associations connected with a variety of professions. The Company also uses internship programs to introduce individuals to the Company's business operations and provide a possible source of future employees.

Being employee driven also requires developing employees in their current positions and for future advancement. The Company provides opportunities for advancement through job mobility, succession planning and promotions both within and between business segments. The Company requires employees included in the succession planning process to participate in and further develop their skills for potential advancement in the future. Succession planning is performed across the organization for all levels of leadership. The Company provides employees the opportunity to further develop and grow through various forms of training, mentorship programs and internship programs, among other things.

MDU Resources Group, Inc. Form 10-K 9

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To attract and retain employees, the Company offers:

The chief executive officer engages in employee tours at Company locations and the Company conducts employee surveys to hear and gauge employee opinions on issues such as integrity, safety, respect, excellence and stewardship. Survey responses are compiled and evaluated at various levels throughout the Company to develop action plans to address areas of concern raised by employees.

Safety Safety is one of the Company's corporate values. The Company is committed to safety and health in the workplace. To ensure safe work environments, the Company provides training, resources and appropriate follow-up on any unsafe conditions or actions. To facilitate a strong safety culture, the Company established its Safety Leadership Council. In addition to the Safety Leadership Council, the Company has policies and training that support safety in the workplace including training on safety matters through classroom and toolbox meetings on job sites. The Company utilizes safety compliance in the evaluation of employees, which includes management, and recognizes employee safety through safety award programs. Accident and safety statistical information is regularly reported to management and the Board.

Environmental Matters The Company believes it has a responsibility to use natural resources efficiently and attempt to minimize the environmental impact of its activities. The Company produces GHG emissions primarily from its fossil fuel electric-generating facilities, as well as from natural gas pipeline and storage systems, and operations of equipment and fleet vehicles. The Company has developed renewable generation with lower or no GHG emissions. Governmental legislation and regulatory initiatives regarding environmental and energy policy are continuously evolving and could negatively impact the Company's operations and financial results. The Company will continue to monitor legislative and regulatory activity related to environmental and energy policy initiatives and take all appropriate action to comply. In addition, for a discussion of the Company's risks related to environmental laws and regulations, see Item 1A - Risk Factors.

For more information on the Company's environmental, social and governance initiatives and goals, practices and progress, see the Company's Impact Report on its website, which is not incorporated by reference herein.

10 MDU Resources Group, Inc. Form 10-K

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Governmental Matters The Company's operations and certain of its subsidiaries are subject to laws and regulations relating to air, water and solid waste pollution control; federal and state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal and state health and safety regulations; and state hazard communication standards. The Company strives to be in compliance with applicable regulations. For more information, see Environmental matters in Item 8 - Note 17. There are no pending CERCLA actions for any of the Company's material properties. However, the Company is involved in certain claims relating to the Bremerton Gasworks Superfund Site. For more information on the Company's environmental matters, see Item 8 - Note 17 and Item 7 - MD&A - Business Section Financial and Operating Data.

Technology The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information technology systems and network infrastructure. For a discussion of the Company's risks related to cybersecurity, see Item 1A - Risk Factors. For more information on the Company's approach to cybersecurity, see Item 1C - Cybersecurity.

Available Information The Company maintains a corporate website at www.mdu.com. The Company's filings with the SEC, including its annual report on Form 10-K, it's quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to those reports are available free of charge through this website as soon as reasonably practicable after they are filed with or furnished to the SEC. The Governance section of the website contains the Company's Corporate Governance Guidelines, committee charters, and the Leading with Integrity Policy for directors, officers, and employees, and is incorporated herein by reference. Copies of these documents may also be obtained free of charge upon written request to the Company's corporate secretary at MDU Resources Group, Inc., P.O. Box 5650, Bismarck, North Dakota 58506. The information available on, or accessible through, the Company's website is not part of this Annual Report on Form 10-K.

MDU Resources Group, Inc. Form 10-K 11

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Electric

General The Company's electric segment is operated through its wholly-owned subsidiary, Montana-Dakota. Montana-Dakota provides electric service at retail, serving residential, commercial, industrial and municipal customers in 185 communities and adjacent rural areas.

The material properties owned by Montana-Dakota for use in its electric operations include interests in 15 electric generating units at 12 facilities and two small portable diesel generators, as further described under System Supply, System Demand and Competition, approximately 3,400 and 4,900 miles of transmission and distribution lines, respectively, and 86 transmission and 299 distribution substations. Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. At December 31, 2025, Montana-Dakota's net electric plant investment was $2.1 billion and its rate base was $1.8 billion.

Retail electric rates, service, accounting and certain securities issuances are subject to regulation by the MTPSC, NDPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota are also subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of certain securities, accounting, cybersecurity and other matters.

Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its interconnected system. MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from that market.

The retail customers served and respective revenues by class for the electric business were as follows:

			2025						2024						2023
			Customers Served			Revenues			Customers Served			Revenues			Customers Served			Revenues
			(Dollars in thousands)
Residential			120,678			$	136,676		120,043			$	139,862		119,700			$	134,054
Commercial			23,997			178,991			23,762			165,778			23,573			164,142
Industrial			214			37,762			219			42,320			228			42,340
Other			1,661			7,424			1,662			7,773			1,607			7,075
			146,550			$	360,853		145,686			$	355,733		145,108			$	347,611

Other electric revenues, which are largely transmission-related revenues, for Montana-Dakota were $77.4 million, $58.7 million and $53.6 million for the years ended December 31, 2025, 2024 and 2023, respectively.

12 MDU Resources Group, Inc. Form 10-K

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The percentage of electric retail revenues by jurisdiction was as follows:

			2025			2024			2023
North Dakota			67		%	65		%	66		%
Montana			20		%	21		%	20		%
Wyoming			9		%	9		%	9		%
South Dakota			4		%	5		%	5		%

System Supply, System Demand and Competition Through an interconnected electric system, Montana-Dakota serves markets in portions of North Dakota, Montana and South Dakota. These markets are highly seasonal and sales volumes depend largely on the weather. Additionally, the average customer consumption has tended to decline due to increases in energy efficient lighting and appliances being installed. In mid-2023 a data center began operating in the Company's service territory which led to an increase in retail sales revenue and volumes. The Company currently serves this data center with an approach that requires minimal new capital investment, which not only benefits the Company's earnings and rate of return, but also provides cost savings to the Company's other retail customers. As of December 31, 2025, the interconnected system consisted of 14 electric generating units at 11 facilities and two small portable diesel generators. Additional details are included in the table that follows. For 2025, Montana-Dakota's total ZRCs, including its firm purchase power contracts, were 558.6. Montana-Dakota's planning reserve margin requirement within MISO was 529.2 ZRCs for 2025. The maximum electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was 764,823 kW in January 2024. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will occur during the summer. Additional energy is purchased as needed, or in lieu of generation if more economical, from the MISO market. In 2025, Montana-Dakota purchased approximately 60 percent of its net kWh needs for its interconnected system through the MISO market.

Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 69,991 kW in July 2024. Montana-Dakota has a power supply contract with Black Hills Power, Inc. to purchase up to 49,000 kW of capacity annually through December 31, 2028. Wygen III also serves a portion of the needs of Montana-Dakota's Sheridan-area customers.

Approximately 40 percent of the electricity delivered to customers from Montana-Dakota's owned generation in 2025 was from renewable resources. Although Montana-Dakota's generation resource capacity has increased to serve the needs of its customers, the carbon dioxide emission intensity of its electric generation resource fleet has been reduced by approximately 44 percent since 2005 through the addition of renewable generation and with the retirement of aging coal-fired electric generating units, as further discussed below.

In February 2022, the Company ceased operations of Units 1 and 2 at Heskett Station near Mandan, North Dakota, and decommissioning was completed in December 2023. In May 2022 Montana-Dakota began construction of Heskett Unit 4, an 88-MW simple-cycle natural gas-fired combustion turbine peaking unit at the existing Heskett Station near Mandan, North Dakota. Heskett Unit 4 was in service and fully operational in July 2024. In December 2025, the Company acquired and placed in service a 49 percent ownership interest in Badger Wind Farm.

MDU Resources Group, Inc. Form 10-K 13

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The following table sets forth details applicable to the Company's electric generating stations:

Generating Station			Type			Fuel			Nameplate Rating (kW) at December 31, 2025			2025 ZRCs			(a)			2025 Net Generation (kWh in thousands)
Interconnected System:
North Dakota:
Coyote (b)			Steam			Coal			103,647			96.4						540,307
Heskett			Combustion turbine			Natural gas			176,632			158.8						58,942
Glen Ullin			Renewable			Heat recovery			7,500			2.9						32,374
Cedar Hills			Renewable			Wind			19,500			—						47,730
Thunder Spirit			Renewable			Wind			155,500			33.4						568,822
Badger Wind Farm (b)			Renewable			Wind			127,100			—						937
South Dakota:
Big Stone (b)			Steam			Coal			94,111			102.7						470,417
Montana:
Lewis & Clark			Reciprocating internal combustion engine			Natural gas			18,700			16.6						11,789
Glendive			Combustion turbine			Natural gas / diesel			75,522			55.6						17,506
Miles City			Combustion turbine			Natural gas / diesel			23,150			16.9						2,527
Diamond Willow			Renewable			Wind			30,000			5.5						88,265
Portable Units (2)			Reciprocating internal combustion engine			Diesel			3,650			3.5						18
									835,012			492.3						1,839,634
Sheridan System:
Wyoming:
Wygen III (b)			Steam			Coal			28,000			N/A						—
									863,012			492.3						1,839,634

(a)Interconnected system only. MISO requires generators to obtain their seasonal capability through the GVTC. The GVTC is then converted to ZRCs by applying each generator's forced outage factor against its GVTC. Wind generator's ZRCs are calculated based on a wind capacity study performed annually by MISO. ZRCs are used to meet supply obligations within MISO.

(b)Reflects Montana-Dakota's ownership interest.

The owners of Coyote Station, including Montana-Dakota, have a contract with Coyote Creek for coal supply to the Coyote Station that expires December 2040. Montana-Dakota estimates the Coyote Station coal supply agreement to be approximately 1.5 million tons per contract year. For more information, see Item 8 - Note 17.

The owners of Big Stone Station, including Montana-Dakota, have a coal supply agreement with Navajo Transitional Energy Company, LLC to meet all of the Big Stone Station's fuel requirements through 2026. Montana-Dakota estimates the Big Stone Station coal supply agreement to be approximately 1.5 million tons per contract year.

Montana-Dakota has a coal supply agreement with Wyodak Resources Development Corp., to supply the coal requirements of Wygen III at contracted pricing through June 1, 2060. Montana-Dakota estimates the maximum annual coal consumption of the facility to be approximately 585,000 tons.

Montana-Dakota has power purchase agreements that run through 2045.

Montana-Dakota expects that it has secured adequate capacity available through existing baseload generating stations, renewable generation, turbine peaking stations, demand reduction programs and firm contracts to meet the peak customer demand requirements of its customers. Based upon current MISO resource adequacy rules, Montana-Dakota expects that it has secured adequate capacity available through existing baseload generation, peaking stations, demand reduction programs and firm contracts to meet the peak customer demand. MISO's recently approved direct loss of load accreditation is showing the need of additional generating units by May of 2028. Future capacity needs are expected to be met by constructing new generation resources or acquiring additional capacity through power purchase contracts or the MISO capacity auction.

Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.

14 MDU Resources Group, Inc. Form 10-K

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Montana-Dakota is subject to competition resulting from customer demands, technological advances and other factors in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas.

Montana-Dakota is not dependent on any single customer or group of customers for sales of its services, where the loss of which would have a material adverse effect on its business.

Regulatory Matters and Revenues Subject to Refund In North Dakota, Montana, South Dakota and Wyoming, there are various recurring regulatory mechanisms with annual true-ups that can impact Montana-Dakota's results of operations, which also reflect monthly increases or decreases in electric fuel and purchased power costs (including demand charges). Montana-Dakota is deferring those electric fuel and purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. Examples of these recurring mechanisms include: monthly Fuel and Purchased Power Tracking Adjustments, a fuel adjustment clause, and an annual Electric Power Supply Cost Adjustment. Such mechanisms generally provide that these deferred fuel and purchased power costs are recoverable or refundable through rate adjustments which are filed annually. Montana-Dakota's results of operations reflect 95 percent of the increases or decreases from the base purchased power costs and also reflect 85 percent of the increases or decreases from the base coal price, which is also recovered through the Electric Power Supply Cost Adjustment in Wyoming. For more information on regulatory assets and liabilities, see Item 8 - Note 6.

All of Montana-Dakota's wind resources pertaining to electric operations in North Dakota are included in a renewable resource cost adjustment rider. Montana-Dakota also has a transmission tracker in North Dakota to recover transmission costs associated with MISO and SPP, along with certain transmission investments not recovered through retail rates. The tracking mechanism has an annual true-up.

In South Dakota, Montana-Dakota recovers the South Dakota decommissioning regulatory asset, and has proposed to recover other certain infrastructure investments including Badger Wind Farm, through an Infrastructure Rider tracking mechanism that is subject to an annual true-up. Montana-Dakota also has in place in South Dakota a transmission tracker to recover transmission costs associated with MISO and SPP, that allows transmission investments not recovered through retail rates. This tracking mechanism also has an annual true-up.

In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, its allocated share of Montana property-related taxes assessed to electric operations on an after-tax basis.

For more information on regulatory matters, see Item 8 - Note 6.

Environmental Matters Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state, tribal and local authorities; federal and state health and safety regulations; and state hazard communication standards. Montana-Dakota is required to acquire and comply with a wide variety of environmental licenses, registrations, permits, approvals and/or agreements which may involve activities related to construction permitting, air quality and emissions, water quality, wastewater and stormwater discharges, wildlife, endangered species, avian interactions, waste handling, natural resources protection, historic and cultural resource protection, and other similar activities. The electric operations strive to be in compliance with these regulations.

Montana-Dakota's thermal electric generating facilities have Title V Operating Permits, under the federal Clean Air Act issued by the states in which they operate. Each of these permits has a five-year life. Other facilities or operations may require minor source air permits or other registrations. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration.

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State water discharge permits issued under the requirements of the federal Clean Water Act are maintained for thermal electric generating facilities. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by the Company's facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army Corps permits to construct water intake structures. Army Corps permits grant one-time permission to construct and do not require renewal. Extensions to one time permits are obtained as needed. Other permit terms vary and permits are renewed as necessary.

Montana-Dakota's electric operations are very small-quantity generators of hazardous waste and subject only to minimum regulation under the RCRA and when required notifies federal and state agencies of episodic generation events. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.

Montana-Dakota incurred approximately $1.2 million of capital expenditures in 2025 related to maintaining compliance with air emissions and coal ash management regulations, primarily at the Company's co-owned coal-fired electric generation facilities. Environmental related capital expenditures are estimated to be $1.5 million, $1.8 million and $1.0 million in 2026, 2027 and 2028, respectively, for air emissions and coal ash management compliance at its co-owned coal-fired generation facilities. Montana-Dakota does not expect to incur any material capital expenditures in 2026, 2027 and 2028 for compliance with current environmental laws and regulations. Montana-Dakota's capital and operational expenditures could also be affected by future environmental requirements, such as existing and proposed emissions reduction plans from the EPA. For more information, see Item 1A - Risk Factors and Item 7 - MD&A - Business Section Financial and Operating Data.

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Natural Gas Distribution

General The Company's natural gas distribution segment is operated through its wholly-owned subsidiaries, consisting of operations from Montana-Dakota, Cascade and Intermountain. These companies sell natural gas at retail, serving residential, commercial and industrial customers in 343 communities and adjacent rural areas across eight states. They also provide natural gas transportation services to certain customers on the Company's systems.

These services are provided through distribution and transmission systems aggregating approximately 22,000 miles and 540 miles, respectively. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. These operations intend to seek renewal of all expiring franchises. At December 31, 2025, the natural gas distribution operations' net natural gas distribution plant investment was $2.8 billion and its rate base was $2.2 billion.

The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates, service, accounting and certain securities issuances.

The retail customers served and respective revenues by class for the natural gas distribution operations were as follows:

			2025						2024						2023
			Customers Served			Revenues			Customers Served			Revenues			Customers Served			Revenues
			(Dollars in thousands)
Residential			965,378			$	680,035		950,094			$	651,810		935,235			$	726,064
Commercial			115,898			423,872			114,436			400,821			112,966			441,199
Industrial			1,053			45,229			1,063			42,687			1,074			45,009
			1,082,329			$	1,149,136		1,065,593			$	1,095,318		1,049,275			$	1,212,272

Transportation and other revenues for the natural gas distribution operations were $134.4 million, $105.8 million and $75.3 million for the years ended December 31, 2025, 2024 and 2023, respectively. In 2025 and 2024, other revenue includes revenues from the sale of allocated emissions allowances.

The percentage of the natural gas distribution operations' retail sales revenues by jurisdiction was as follows:

			2025			2024			2023
Washington			35		%	34		%	28		%
Idaho			24		%	29		%	33		%
North Dakota			14		%	12		%	12		%
Oregon			8		%	10		%	9		%
Montana			8		%	7		%	8		%
South Dakota			6		%	5		%	5		%
Minnesota			3		%	2		%	3		%
Wyoming			2		%	1		%	2		%

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System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting principally of residential and commercial space and water heating users, in portions of Idaho, Minnesota, Montana, North Dakota, Oregon, South Dakota, Washington and Wyoming. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are mitigated in certain jurisdictions by weather normalization mechanisms discussed later in Regulatory Matters. Additionally, the average customer consumption has tended to decline as more efficient appliances and furnaces are installed and as the Company has implemented conservation programs. In addition to the residential and commercial sales, the utilities transport natural gas for larger commercial and industrial customers who purchase their own supply of natural gas.

Competition resulting from customer demands, technological advances and other factors exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial loads. These rates have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain customers have bypassed the distribution systems by directly accessing transmission pipelines within close proximity. These bypasses do not have a material effect on results of operations.

The natural gas distribution operations and various distribution transportation customers obtain natural gas for their system requirements directly from producers, processors and marketers. The Company's purchased natural gas is supplied by a portfolio of contracts specifying market-based pricing and is transported under transportation agreements with various pipelines, including WBI Energy Transmission. The natural gas distribution operations have contracts for storage services to provide gas supply during the winter heating season and to meet peak day demand with various storage providers, including WBI Energy Transmission and other third party providers. In addition, certain of the operations have entered into natural gas supply management agreements with various parties. Demand for natural gas, which is a widely traded commodity, has historically been sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The Company believes supplies are adequate for the natural gas distribution operations to meet its system natural gas requirements for the next decade. This belief is based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available through its suppliers and pipeline service providers.

Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation, storage and environmental compliance costs. Current tariffs allow for recovery or refunds of under- or over-recovered costs through rate adjustments which are filed annually.

In North Dakota and South Dakota, Montana-Dakota's natural gas tariffs contain weather normalization mechanisms applicable to certain firm customers that adjust the distribution delivery charges to reflect weather fluctuations during the November 1 through May 1 billing periods.

In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, its allocated share of Montana property-related taxes assessed to natural gas operations on an after-tax basis.

In Minnesota, Great Plains recovers qualifying capital investments related to the safety and integrity of the pipeline systems through a cost recovery tracking mechanism.

In Oregon, Cascade has a decoupling mechanism in place approved by the OPUC until January 1, 2030, with a review which is to be completed by September 30, 2029. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC.

In Washington, Cascade has a full decoupling mechanism where Cascade is allowed recovery of an average revenue per customer regardless of actual consumption. The mechanism also includes an earnings sharing component if Cascade earns in excess of its authorized return.

In Idaho, Intermountain has the authority to facilitate access for RNG producers to the Company's distribution system for the purpose of moving RNG to the producer's end-use customers.

For more information on regulatory matters, see Item 8 - Note 6.

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Environmental Matters The natural gas distribution operations are subject to federal, state, tribal and local environmental, facility-siting, zoning and planning laws and regulations. The natural gas distribution operations strive to be in compliance with these regulations. The Company is required to acquire and comply with a wide variety of environmental licenses, registrations, permits, approvals and/or agreements which may involve activities related to construction permitting, air quality and emissions, water quality, wastewater and stormwater discharges, waste handling, natural resource protection, historic and cultural resource protection, and other similar activities.

The Company's natural gas distribution operations are very small-quantity generators of hazardous waste, and subject only to minimum regulation under the RCRA. A Washington state rule defines Cascade as a small-quantity generator, but regulation under the rule is similar to RCRA. Certain locations of the natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Capital and operational expenditures for natural gas distribution operations could be affected in a variety of ways by new GHG legislation or regulation. In particular, such legislation or regulation would likely increase capital expenditures for energy efficiency and conservation programs and operational and gas supply costs associated with GHG emissions compliance. Natural gas distribution operations expect to recover the operational and capital expenditures for GHG regulatory compliance in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations. For more information, see Item 7 - MD&A - Business Section Financial and Operating Data.

The natural gas distribution operations incurred $8.3 million of capital expenditures in 2025 to construct infrastructure supporting multiple RNG facilities, including the development and construction of a RNG facility at the Deschutes County Landfill near Bend, Oregon, and other GHG reduction projects. Cascade and Montana-Dakota expect to incur environmental related capital expenditures of $15.9 million, $10.6 million and $7.7 million, in 2026, 2027 and 2028, respectively. The capital expenditures are to continue construction of infrastructure supporting multiple RNG production facilities, implement a thermal energy network pilot project, other GHG reduction projects, and investigate a historic manufactured gas plant site. Except as to what may be ultimately determined with regard to the issues described in the following paragraph and the items noted, the natural gas distribution operations do not expect to incur any material capital expenditures related to compliance with current environmental laws and regulations through 2028.

Montana-Dakota has ties to six historic manufactured gas plants as a successor corporation or through direct ownership of the plant. Montana-Dakota is investigating possible soil and groundwater impacts due to the operation of two of these former manufactured gas plant sites. To the extent not covered by insurance, Montana-Dakota may seek recovery in its natural gas rates charged to customers for certain investigation and remediation costs incurred for these sites. Cascade has ties to eight historic manufactured gas plants as a successor corporation or through direct ownership of the plant. Cascade is involved in the investigation and remediation of one of these manufactured gas plants in Washington. To the extent not covered by insurance, Cascade will seek recovery of investigation and remediation costs through its natural gas rates charged to customers.

See Item 8 - Note 17 for further discussion of certain manufactured gas plant sites.

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Pipeline

General WBI Energy owns and operates WBI Energy Transmission, a FERC regulated pipeline, which consists of over 3,800 miles of natural gas transmission and storage lines and comprised approximately 94 percent of the segment's revenue in 2025. WBI Energy also owns and operates a non-regulated energy-related service business, specializing in cathodic protection, which comprised the additional 6 percent of the segment's revenue.

WBI Energy Transmission's underground storage fields provide natural gas storage services to local distribution companies, industrial customers, natural gas marketers and others, and serve to enhance system reliability. Its system is strategically located near four natural gas producing basins, making natural gas supplies available to its transportation and storage customers. The system has 14 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country and from Canada. Under the Natural Gas Act, as amended, WBI Energy Transmission is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters, and at December 31, 2025, its net plant investment was $1.0 billion.

A majority of the pipeline business is transacted in the Rocky Mountain and northern Great Plains regions of the United States.

System Supply, System Demand and Competition Natural gas supplies emanate from traditional and nontraditional production activities in the region from both on-system and off-system supply sources. Incremental supply from nontraditional sources, such as the Bakken area in Montana and North Dakota, have helped offset declines in traditional regional supply sources and supports WBI Energy Transmission's transportation and storage services. In addition, off-system supply sources are available through the Company's interconnections with other pipeline systems. WBI Energy Transmission continues to look for opportunities, such as the identified growth projects discussed in Item 7 - MD&A - Pipeline Outlook, to increase transportation and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide future benefits.

WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 350 Bcf, including 193 Bcf of working gas capacity, 83 Bcf of cushion gas and 74 Bcf of native gas. These storage facilities enable customers to purchase natural gas throughout the year and meet winter peak requirements.

WBI Energy Transmission competes with several pipelines for its customers' transportation business and at times may discount rates in an effort to retain market share; however, the strategic location of its system near four natural gas producing basins and the availability of underground storage services, along with interconnections with other pipelines, enhances its competitive position.

Although certain of WBI Energy Transmission's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure residential, commercial and industrial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.

WBI Energy Transmission transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for 2025 represented 19 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the firm transportation agreements with Montana-Dakota expire in June 2027. In addition, Montana-Dakota has a contract, expiring in July 2035, with WBI Energy Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements.

The non-regulated business of this segment competes for existing customers in the areas in which it operates. Its focus on customer service and the variety of services it offers serve to enhance its competitive position.

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WBI Energy is not dependent on any single customer or group of customers for sales of its services, where the loss of which would have a material adverse effect on its business. WBI Energy had one third-party customer that accounted for approximately 17 percent of its 2025 revenue.

Environmental Matters The pipeline operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations.

Administration of certain provisions of federal environmental laws is delegated to the states where WBI Energy and its subsidiaries operate. Administering agencies may issue permits with varying terms and operational compliance conditions. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand, facility upgrades or modifications, and/or regulatory changes. The pipeline operations strive to be in compliance with these regulations.

Detailed environmental assessments and/or environmental impact statements as required by the National Environmental Policy Act are included in the FERC's environmental review process for both the construction and abandonment of WBI Energy Transmission's natural gas transmission pipelines, compressor stations and storage facilities.

The pipeline operations did not incur any material capital expenditures related to compliance with current environmental laws and regulations in 2025 and have no planned capital expenditures to meet compliance requirements of environmental laws and regulations in 2026. Capital expenditures to meet requirements of the EPA rules, as previously discussed, are included in the capital expenditures for 2028 and estimated at $4.0 million. For more information on the capital expenditures for this segment, see Item 7 - MD&A - Capital Expenditures.

Discontinued Operations

General Discontinued operations includes the historical operations of Knife River and Everus, as well as associated strategic initiative costs and interest on certain third party debt facilities repaid in connection with the Knife River and Everus separations. The Company completed the separations of Knife River and Everus on May 31, 2023 and October 31, 2024, respectively. Discontinued operations also includes the supporting activities of Fidelity other than certain general and administrative costs and interest expense. For more information on discontinued operations, see Item 8 - Note 3.

Item 1A. Risk Factors

The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents filed with the SEC. The factors and other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document. If any of the risks described below actually occur, the Company's business, prospects, financial condition or financial results could be materially harmed. The following are the most material risk factors applicable to the Company and are not necessarily listed in order of importance or probability of occurrence.

Economic Risks

The Company is subject to government regulations that may have a negative impact on its business and its results of operations and cash flows.

The Company's businesses are subject to comprehensive regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return and recovery of investments and costs; financing; rate structures; customer service; health care coverage and costs; taxes; franchises; recovery of fuel, purchased power and purchased natural gas costs; carbon compliance obligations costs; and construction and siting of generation, distribution and transmission facilities. These governmental regulations significantly influence the Company's operating environment and may, among other things, affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could also have an adverse impact on the Company's results of operations and cash flows.

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In the normal course of business, the Company often places assets in service and establishes historical test periods before rate cases that seek to adjust customer rates and the Company's allowed rate of return to recover those investments can be filed for. The rate case review policy varies by jurisdiction in which the Company operates and is as long as eleven months in certain states. Because of this process, the Company could have assets placed in service without the benefit of rate relief, commonly referred to as regulatory lag. In certain jurisdictions, regulatory authorities have approved various infrastructure and annual rate adjustment mechanisms to effectively reduce regulatory lag inherent in the rate making process. Regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. There can be no assurance that applicable regulatory commissions will determine that the Company's costs have been prudent, which could result in the disallowance of costs in setting rates for customers. Also, the regulatory process of approving rates for these businesses may not allow for timely and full recovery of the costs of providing services or a return on the Company's invested capital. Changes in regulatory requirements or operating conditions may require early retirement of certain assets. While regulation typically provides rate recovery for these retirements, there is no assurance regulators will allow full recovery of all remaining costs, which could leave stranded asset costs. Rising fuel costs could increase the risk that the utility businesses will not be able to fully recover those fuel costs from customers.

The utility operates under franchise agreements granted by municipalities, which allow the Company to access public rights-of-way and provide utility services within city boundaries. These agreements typically require renewal every set number of years and risks include items such as potential non-renewal and renegotiation which could result in less favorable terms, additional fees or new operational obligations. Failure to obtain or renew franchise agreements on acceptable terms could materially affect the Company's ability to serve its customers in those jurisdictions.

Economic volatility affects the Company's operations, as well as the demand for its services.

Economic conditions and population growth affect the electric and natural gas distribution businesses' growth in service territory, customer base and usage demand. Economic volatility in the markets served, along with economic conditions such as increased customer rates and unemployment which could impact the ability of the Company's customers to make payments, could adversely affect the Company's results of operations, cash flows and asset values. Further, any material decreases in customers' energy demand, for economic or other reasons, could have an adverse impact on the Company's earnings and results of operations.

Demand for energy from high volume customers may impact the Company's business.

The ability to serve significant new commercial or industrial customers, including data centers and significant pipeline projects, may require certain regulatory approvals, and the activities and related costs could be significant. The inability or delays in obtaining regulatory approvals or securing necessary infrastructure to support such projects, due to supply chain risk, operational risk, or other factors, may impact the Company's ability, or the cost, to provide energy to new customers. The contract rates may not fully recover the costs, the contracts may increase counterparty credit risk, and the costs to provide service may be higher than expected. The addition of high volume customers or multiple customers serving the same industry, such as data center load, may increase the concentration of sales and increase revenue and earnings volatility.

Additionally, demand for electricity associated with data center expansion could lead to an increase in demand for electric power in the MISO and in the Company's service territory, which could lead to an increase in generation capacity and grid infrastructure needed and could impact prices for customer energy purchased on the MISO market. Alternatively, this rapid expansion of data centers and resulting increase in demand for electric power may not develop as planned.

The Company's operations involve risks that may result from catastrophic events.

The Company's operations include a variety of inherent hazards and operating risks, such as product leaks; explosions; mechanical failures; vandalism; fires; wildfires; pandemics; social or civil unrest; protests and riots; natural disasters; cyberattacks; acts of terrorism; and acts of war. These hazards and operating risks may occur in the future, which could result in loss of human life; personal injury; property damage; environmental impacts; impairment of operations; and substantial financial losses. The Company maintains insurance against some, but not all, of these risks and losses. A significant incident could also increase regulatory scrutiny and result in penalties and higher amounts of capital expenditures and operational costs. Losses not fully covered by insurance could have an adverse effect on the Company’s financial position, results of operations and cash flows.

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A disruption of the regional electric transmission grid, local distribution infrastructure or interstate natural gas infrastructure could negatively impact the Company's business and reputation. There have been cyber and physical attacks within the energy industry on energy infrastructure, such as substations, and such attacks may occur in the future. Because the Company's electric and natural gas utility and pipeline systems are part of larger interconnecting systems, any attacks on the interconnected systems or the Company's infrastructure causing a disruption could result in a significant decrease in revenues and an increase in system repair costs negatively impacting the Company's financial position, results of operations and cash flows.

Liabilities from wildfires could have a negative impact on the Company's operations or financial performance, and the Company's protocols may not prevent such liability. The Company invests resources on initiatives designed to mitigate wildfire risks; however, the potential for a wildfire event exists even when effective mitigation procedures are followed. Despite the Company's wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which would subject the Company to significant liability. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, uninsured losses or losses in excess of current insurance coverage, increased costs of insurance, damage to the Company's reputation, regulatory recovery risk, litigation risk, the potential for a credit downgrade or the inability to access capital markets on reasonable terms.

The Company’s insurance policies have limits and exclusions that may not fully mitigate losses, and an increase in cost, or the unavailability or cancellation of third-party insurance coverages, would increase the Company’s overall risk exposure.

The Company maintains insurance coverages from third party insurers as part of its overall risk management strategy and most of its contracts require the Company to maintain specific insurance coverage limits. The Company maintains insurance policies with respect to workers’ compensation, auto liability, general liability, excess liability, contractors pollution liability, legal liability, professional liability, directors and officers liability, employment practices liability, cyber policy, terrorism, property and other types of coverages, but these policies are subject to deductibles and the Company is self-insured up to the amount of those deductibles. Insurance losses are accrued based upon the Company's estimates of the ultimate liability for claims reported and an estimate of claims incurred but not yet reported. Insurance liabilities are difficult to assess and estimate due to unknown factors, including the frequency and severity of injuries, the magnitude of damage to or loss of property or the environment, the determination of the Company's liability in proportion to other parties, estimates of incidents not reported and the effectiveness of the Company's safety programs, and as a result, the Company's actual losses may exceed its estimates. There can be no assurance that the Company's current or past insurance coverages will be sufficient or effective under all circumstances or against all claims and liabilities, including claims resulting from wildfires or other natural disasters, to which the Company may be subject.

The Company generally renews its insurance policies on an annual basis; therefore, deductibles and levels of insurance coverages may change in future periods. There can be no assurance that any of the Company's existing insurance coverages will be renewed upon the expiration of the coverage period or that future coverage will be available at reasonable and competitive rates or at the required limits. The cost of the Company's insurance has significantly increased over time and may continue to increase in the future. In addition, insurers may fail, cancel the Company's coverage, increase the cost of coverage, determine to exclude certain items from coverage, or otherwise be unable to provide the Company with adequate insurance coverage. The Company may not be able to obtain certain types of insurance or incremental levels of insurance in scope or amount sufficient to cover liabilities it may incur. For example, due to the increase in wildfire losses and related insurance claims, insurers have reduced coverage availability and increased the cost of insurance coverage for such events in recent years, and the Company's current levels of coverage may not be sufficient to cover potential losses. If the Company's risk exposure increases as a result of adverse changes in its insurance coverage, the Company could be subject to increased liabilities that could negatively affect its business, financial condition, results of operations and cash flows.

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In addition, the Company performs work in hazardous environments and its employees are exposed to a number of hazards. Incidents can occur, regardless of fault, that may be catastrophic and adversely impact the Company's employees and third parties by causing serious personal injury, loss of life, damage to property or the environment, and interruption of operations. In locations or environments where claims have become more frequent or severe in recent years, insurance may become difficult or impossible to obtain. The Company's contracts may require it to indemnify other parties for injury, damage or loss arising out of the Company's presence at its customers’ location, or in the performance of the Company's work, in both cases regardless of fault, and provide for warranties of materials and workmanship. The Company also may be required to name other parties as an additional insured party under its insurance policies. The Company maintains limited insurance coverage against these and other risks associated with its business. This insurance may not protect the Company against liability for certain events, and the Company cannot guarantee that its insurance will be adequate in risk coverage or policy limits to cover all losses or liabilities that it may incur. Any future damages caused by the Company's services that are not covered by insurance or are in excess of policy limits could negatively affect its business, financial condition, results of operations and cash flows.

The Company is subject to capital market, debt, and interest rate risks and may be unable to obtain the financing required at acceptable terms, or at all.

The Company's operations and growth plans require significant capital investment. Consequently, the timing, magnitude, and sources of capital required may exceed cash flows from operations and, as such, the Company relies on financing sources and capital markets as sources of liquidity for capital requirements and may require non-traditional financing sources, such as partnerships. If the Company is not able to access capital at competitive rates, the ability to implement business plans, make capital expenditures or pursue acquisitions the Company would otherwise rely on for future growth may be adversely affected. Market disruptions may increase the cost of borrowing or adversely affect the Company's ability to access one or more financial markets. Such disruptions could include items such as a significant economic downturn, the financial distress of unrelated industry leaders in the same line of business, the deterioration of capital market conditions, turmoil in the financial services industry, volatility in commodity prices, increased trade tariffs and trade disputes with other countries, supply chain weaknesses, pandemics, natural disasters, war, terrorist attacks and cyberattacks.

The Company’s inability to generate sufficient cash flow to satisfy or refinance its debt obligations could adversely affect its business, financial condition, results of operations, and other corporate requirements. This could require the Company to direct a substantial portion of its future cash flow toward payments on its indebtedness, which would reduce the amount of cash flow available to fund working capital, capital expenditures, and other corporate requirements, thereby limiting its ability to respond to business opportunities.

If the Company does not comply with its financial covenants and does not obtain a waiver or amendment from its lenders, the lenders may elect to cause any amounts then owed to become immediately due and payable, not fund any new borrowing, or they may decline to renew the Company’s credit facility. In that event, the Company would seek to establish a replacement credit facility with one or more other lenders, including lenders with which it has an existing relationship, potentially on less desirable terms. There can be no guarantee that replacement financing would be available at commercially reasonable terms, if at all. Higher interest rates on borrowings have impacted and could further impact the Company's future operating results.

The issuance of a substantial amount of the Company's common stock, whether issued in connection with an acquisition or otherwise, would have a dilutive effect on stockholders, and such an issuance, or perception that such an issuance may occur, could adversely affect the market price of the Company's common stock.

Significant changes in prices for commodities, labor, or other production and delivery inputs and other environmental compliance costs could negatively affect the Company's businesses.

The Company's operations are exposed to fluctuations in prices for labor, petroleum products, raw materials and services, pipeline transportation charges, and costs of credits for carbon allowance programs. Prices are generally subject to change in response to fluctuations in supply and demand and other general economic and market conditions beyond the Company's control.

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Fluctuations in oil and natural gas production, supplies and prices; fluctuations in commodity price basis differentials; political and economic conditions in oil-producing countries; actions of the Organization of Petroleum Exporting Countries; demand for oil due to economic conditions; war and other external factors impact the development of oil and natural gas supplies and the expansion and operation of natural gas pipeline systems. The Company has benefited from associated natural gas production in the Bakken, which has provided opportunities for organic growth projects. Depressed oil and natural gas prices; however, place pressure on the ability of oil exploration and production companies to meet credit requirements and can be a challenge if prices remain depressed long-term. Prolonged depressed prices for oil and natural gas could negatively affect the growth, results of operations, cash flows and asset values of the Company's electric, natural gas and pipeline businesses.

If oil and natural gas prices increase significantly, which has occurred and may reoccur, customer demand could decline for utility and pipeline services, which could impact the Company's results of operations and cash flows. While the Company has fuel clause recovery mechanisms for its utility operations in all of the states where it operates, higher utility fuel costs could also significantly impact results of operations if such costs are not recovered. Delays in the collection of utility fuel cost recoveries, as compared to expenditures for fuel purchases, could also negatively impact the Company's cash flows.

Increased labor costs, due to labor shortages, competition from other industries, or other factors, could negatively affect the Company's results of operations.

In 2025, 2024 and 2023, the Company experienced elevated commodity and supply chain costs at varying degrees over the 3-year timeframe, including the costs of labor, raw materials, energy-related products and other inputs used for constructing the facilities the Company uses to provide its services.

If environmental compliance costs increase significantly, customer demand could decline for the natural gas distribution segment, which could impact the Company’s results of operations and cash flows. While the Company has environmental compliance recovery mechanisms, higher costs could also significantly impact results of operations if such costs are not recovered. Delays in the collection of environmental compliance costs, as compared to expenditures for environmental compliance costs, could also negatively impact the Company’s cash flows.

The Company's operations could be negatively impacted by import tariffs, changes in trade policy, and/or other government mandates.

The Company operates in or provides services to capital intensive industries in which federal trade policies could significantly impact the availability and cost of materials. Imposed and proposed tariffs could significantly increase the prices and delivery lead times on raw materials and finished products that are critical to the Company and its customers. Prolonged lead times on the delivery of raw materials and further tariff increases on raw materials and finished products could adversely affect the Company's business, financial condition and results of operations.

The United States government has implemented changes, and may do so again, to trade policy and introduced tariffs on a range of products from certain countries, in addition to applying baseline tariffs on imports from most countries. These actions have created uncertainty in global markets and have increased and may continue to increase the cost of raw materials, commodities, supplies and equipment purchased by the Company. Additionally, the tariff and trade policy changes could cause supply chain disruptions and delays in sourcing materials and equipment which could delay large capital projects and negatively impact the Company's financial condition and results of operations. If the Company's regulators do not determine the increased costs are prudent, or otherwise disallow certain costs, it could impact the Company's ability to recover the cost increases through rates or on a timely basis, which could adversely affect the Company's financial condition and results of operations.

Reductions in the Company's credit ratings or inability to obtain a credit rating could increase financing costs.

There is no assurance the Company's current credit ratings, or those of its subsidiaries, will remain in effect or that a rating will not be lowered or withdrawn by a rating agency. Events affecting the Company's, including its subsidiaries', financial results may impact its cash flows and credit metrics, potentially resulting in a change in the Company's or its subsidiaries' credit ratings. The Company's or its subsidiaries' credit ratings may also change as a result of the differing methodologies or changes in the methodologies used by the rating agencies.

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Increasing costs associated with health care plans and changes in employment laws or regulations may adversely affect the Company's results of operations.

The Company's self-insured costs of health care benefits for eligible employees continues to increase. Increasing quantities of large individual health care claims and an overall increase in total health care claims could have an adverse impact on operating results, financial position and liquidity. Complying with any new legislation and regulation at both the federal and state levels related to health care, unemployment tax rates and workers' compensation rates, among others, could adversely affect the Company's results of operations as well as change the Company's benefit program and costs.

The Company is exposed to risk of loss resulting from the nonpayment and/or nonperformance by the Company's customers and counterparties.

If the Company's customers or counterparties experience financial difficulties, which has occurred and may reoccur in the future, the Company could experience difficulty in collecting receivables. Nonpayment and/or nonperformance by the Company's customers and counterparties, particularly customers and counterparties of the Company’s pipeline business, could have a negative impact on the Company's results of operations and cash flows. The Company could also have indirect credit risk from participating in energy markets such as MISO in which credit losses are socialized to all participants.

Changes in tax law and other regulations may negatively affect the Company's business.

Changes to federal, state and local tax laws have the ability to benefit or adversely affect the Company's earnings and customer costs. Significant changes to corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law at the time of deferral. The electric business owns and operates renewable energy generating facilities. These facilities generate production tax credits used to reduce the Company's federal income tax liability. The amount of production tax credits earned depends on the date the qualifying generating facilities are placed in service and various operating and economic factors, including facility generation, transmission constraints, and wind production. These factors could impact the level of production tax credits. Regulation incorporates changes in tax law into the rate-setting process, which could create timing delays before the impact of changes are realized.

Financial market changes could impact the Company’s pension and postretirement benefit plans and obligations.

The Company has pension and postretirement defined benefit plans for some of its current and former employees. Assumptions regarding future costs, returns on investments, interest rates and other actuarial assumptions have a significant impact on the funding requirements and expense recorded relating to these plans. Adverse changes in economic indicators, such as consumer spending, inflation data, interest rate changes, political developments and threats of terrorism, among other things, can create volatility in the financial markets. These changes could impact the assumptions and negatively affect the value of assets held in the Company's pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions for those plans.

Operational Risks

Significant portions of the Company’s natural gas pipelines and power generation and transmission facilities are aging. The aging infrastructure may require significant additional maintenance or replacement that could adversely affect the Company’s results of operations.

Certain risks increase as the Company's energy delivery infrastructure ages, including breakdown or failure of equipment, pipeline leaks and fires developing from power lines, all of which have occurred and may reoccur in the future resulting in material costs. Aging infrastructure is more prone to failure, which increases maintenance costs, unplanned outages and the need to replace facilities. Even if properly maintained, reliability may ultimately deteriorate and negatively affect the Company’s ability to serve its customers, which could result in increased costs associated with regulatory oversight. The costs associated with compliance with PHMSA rules related to pipeline integrity and other similar programs, maintaining the aging infrastructure and capital expenditures for new or replacement infrastructure could cause rate volatility and/or regulatory lag in some jurisdictions. If, at the end of its life, the investment costs of a facility have not been fully recovered, the Company may be adversely affected if regulatory commissions do not allow such costs to be recovered in rates. Such impacts of aging infrastructure could adversely affect the Company’s results of operations and cash flows.

Additionally, hazards from aging infrastructure could result in serious injury, loss of human life, significant damage to property, environmental impacts and impairment of operations, which in turn could lead to substantial financial losses. The location of facilities near populated areas, including residential areas, business centers, industrial sites and other public gathering places, could increase the damages resulting from these risks. A major incident involving another natural gas system could lead to additional capital expenditures, increased regulation, and fines and penalties on natural gas utilities and pipelines. The occurrence of any of these events could adversely affect the Company’s results of operations, financial position and cash flows.

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The Company's utility and pipeline operations are subject to planning risks.

Most electric and natural gas utility investments, including natural gas transmission pipeline investments, are made with the intent of being used for decades. In particular, electric transmission and generation resources are planned well in advance of when they are placed into service based upon resource plans using assumptions over the planning horizon, including sales growth, commodity prices, equipment and construction costs, regulatory treatment, available technology and public policy. Public policy changes and technology advancements related to areas, such as energy efficient appliances and buildings, renewable and distributive electric generation and storage, carbon dioxide emissions, electric vehicle penetration, restrictions on or disallowance of new or existing services, and natural gas availability and cost may significantly impact the planning assumptions. Changes in critical planning assumptions may result in excess generation, transmission and distribution resources creating increased per customer costs and downward pressure on load growth. These changes could also result in a stranded investment if the Company is unable to fully recover the costs of its investments.

The Company could be subject to penalties, reputational harm, and operational changes if it violates mandatory reliability and security requirements.

The Company is subject to potentially adverse publicity as a result of the reliability of the Company’s services and how quickly the Company responds to certain outages. Adverse publicity could have a negative impact on the Company’s reputation as well as the way that state legislatures, utility commissions and other regulatory authorities view the Company and/or lead to less favorable legislative and regulatory outcomes or increased regulatory oversight. The imposition of any of the foregoing on the Company as a result of its actual or alleged failure to comply with reliability and security requirements could have a negative effect on the Company’s results of operations and financial condition.

The regulatory approval, permitting, construction, startup, and/or operation of pipelines, power generation and transmission facilities may involve unanticipated events, delays, and unrecoverable costs.

The construction, startup and operation of natural gas pipelines and electric power generation and transmission facilities involve many risks, which may include delays; breakdown or failure of equipment; inability to obtain or remain in compliance with required governmental permits and approvals; inability to obtain or renew easements; public opposition; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel supply, off-take, transmission, transportation or other material agreements; contractor performance failures; changes in markets and market prices for power; cost increases and overruns; the risk of performance below expected levels of output or efficiency; the inability to obtain full cost recovery in regulated rates; and the inability to recover preliminary costs incurred prior to receiving regulatory approval. Such unanticipated events could negatively impact the Company's ability to execute on its capital plan, its business, and its results of operations and cash flows.

Operating or other costs required to comply with current or potential pipeline safety regulations and potential new regulations under various agencies could be significant. The regulations require verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of certain lines. Increased emphasis on pipeline safety and increased regulatory scrutiny may result in penalties and higher costs of operations. If these costs are not fully recoverable from customers, they could have an adverse effect on the Company’s results of operations and cash flows.

Supply chain disruptions may adversely affect Company operations.

The Company relies on third-party vendors and manufacturers to supply many of the materials necessary for its operations. Global logistic disruptions have impacted the flow of materials and restricted global trade flows. Manufacturers are competing for a limited supply of key commodities and logistical capacity which has impacted lead times, pricing, supply and demand. Disruptions or delays in receiving materials; price increases from suppliers or manufacturers; or inability to source needed materials, which have occurred and could reoccur, could adversely affect the Company’s capital expenditure programs, growth plans, results of operations, financial condition and cash flows.

Joint ownership of coal-fired generation facilities could impact the Company’s ability to manage changing regulations and economic conditions.

The Company has an ownership interest in three coal-fired electric generating facilities jointly with other co-owners who have varying ownership interests in the facilities. The Company’s ability to make determinations on changing environmental regulations and economic conditions may be impacted by its rights and obligations under the co-ownership agreements and related agreements. Such a determination could impact the Company’s ability to effectively manage these changing conditions to meet its strategic objectives and could adversely impact its financial condition, results of operations and liquidity.

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Environmental and Regulatory Risks

The Company's operations could be adversely impacted by severe weather and changing weather patterns.

Changing weather patterns and severe weather events, such as tornadoes, fires, rain, drought, ice and snowstorms, and high and low temperature extremes, occur in regions in which the Company operates and maintains infrastructure. Climate change could change the frequency and severity of these weather events, which may create physical and financial risks to the Company. Such risks could have an adverse effect on the Company's financial condition, results of operations and cash flows.

Severe weather events may damage or disrupt the Company's electric and natural gas transmission and distribution facilities, which could result in disruption of service and ability to meet customer demand and increase maintenance or capital costs to repair facilities and restore customer service. The cost of providing service could increase if the frequency of severe weather events increases because of climate change or otherwise. The Company may not recover all costs related to mitigating these physical risks.

Utility customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent the largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use by its utility customers due to weather may require the Company to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather may result in decreased revenues. Extreme weather conditions, such as uncommonly long periods of high or low ambient temperature in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the Company's service territory could also have an impact on revenues. The Company buys and sells electricity that might be generated outside its service territory, depending upon system needs and market opportunities. Extreme temperatures may create high energy demand and raise electricity prices, which could increase the cost of energy provided to customers.

Climate change may impact a region’s economic health, which could impact revenues at all of the Company's businesses. The Company's financial performance is tied to the health of the regional economies served. The Company provides natural gas and electric utility service for some states and communities that are economically affected by the agriculture industry. Increases in severe weather events or significant changes in temperature and precipitation patterns could adversely affect the agriculture industry and, correspondingly, the economies of the states and communities affected by that industry.

The insurance industry may be adversely affected by severe weather events, which may impact availability of insurance coverage, insurance premiums and insurance policy terms.

The Company may be subject to litigation related to climate change. Costs of such litigation could be significant, and an adverse outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages, which could affect the Company's results of operations and cash flows if the costs are not recoverable in rates.

The price of energy also has an impact on the economic health of communities. The cost of additional regulatory requirements related to climate change, such as regulation of carbon dioxide emissions under the federal Clean Air Act, requirements to replace fossil fuels with renewable energy or credits, or other environmental regulation or taxes, could impact the availability of goods and the prices charged by suppliers, which would normally be borne by consumers through higher prices for energy and purchased goods, and could adversely impact economic conditions of areas served by the Company. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect the Company's ability to access capital markets or result in less competitive terms and conditions.

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The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

The Company is subject to environmental laws and regulations affecting many aspects of its operations, including air and water quality, wastewater discharge, the generation, transmission and disposal of solid waste and hazardous substances, and other environmental considerations. These laws and regulations can increase capital, operating and other costs; cause delays as a result of litigation and administrative proceedings; and create compliance, remediation, containment, monitoring and reporting obligations. Environmental laws and regulations can also require the Company to install pollution control equipment at its facilities, clean up spills and other contamination and correct environmental hazards, including payment of all or part of the cost to remediate sites where the Company's past activities, or the activities of other parties, caused environmental contamination. These laws and regulations generally require the Company to obtain and comply with a variety of environmental licenses, permits, inspections and other approvals and may cause the Company to shut down existing facilities due to difficulties in assuring compliance or where the cost of compliance makes operation of the facilities uneconomical. Although the Company strives to comply with all applicable environmental laws and regulations, public and private entities and private individuals may interpret the Company's legal or regulatory requirements differently and seek injunctive relief or other remedies against the Company. The Company cannot predict the outcome, financial or operational, of any such litigation or administrative proceedings.

Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment have been adopted such as the Climate Commitment Act in Washington and the Climate Protection Program Rule in Oregon, requiring natural gas distribution companies to reduce overall GHG emissions, and the EPA's Coal Combustion Residuals Rule, potentially requiring additional management and remediation of electric generation coal ash facilities, and other future rules may be adopted or become applicable to the Company. These laws and other regulations could require the Company to limit the use or output of certain facilities; restrict the use of certain fuels; prohibit or restrict new or existing services; replace certain fuels with renewable fuels; retire and replace certain facilities; install pollution controls; remediate environmental impacts; remove or reduce environmental hazards; or forego or limit the development of resources. Revised or new laws and regulations that increase compliance and disclosure costs and/or restrict operations, particularly if costs are not fully recoverable from customers, could adversely affect the Company's results of operations and cash flows.

Stakeholder actions and increased regulatory activity related to ESG matters, particularly climate change and reducing GHG emissions, could adversely impact the Company's operations, costs of or access to capital and impact or limit business plans.

The Company has faced and may continue to face stakeholder scrutiny related to ESG matters. Certain stakeholders of the Company, such as investors, customers, employees, and lenders, have increased their scrutiny of the impacts and social cost associated with ESG matters, including climate change and certain stakeholders may hold divergent opinions on these issues.

Certain states and customers are seeking cleaner energy sources and may demand alternatives to traditional energy sources. If state or customer sentiment shifts more rapidly than expected, the Company may face reduced demand for its existing services or be pressured to offer new low-carbon solutions. Decarbonization policies on building electrification initiatives could slow or reduce future customer additions in the Company's service territories. Jurisdictions pursuing aggressive GHG reduction strategies may adopt building codes or incentive structures that discourage new natural gas hookups, potentially impacting the Company's long-term growth assumptions. Concern that GHG emissions contribute to global climate change has led to international, federal, state and local legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. The Company may experience significant future costs associated with compliance of such legislative actions. The Company’s primary GHG emission is carbon dioxide from fossil fuels combustion at Montana-Dakota's electric generating facilities, particularly its jointly owned coal-fired facilities.

Treaties, legislation or regulations to reduce GHG emissions in response to climate change may be adopted and can affect the Company's operations by requiring additional energy conservation efforts or renewable energy sources, limiting emissions, imposing carbon taxes or other compliance costs; as well as other mandates that could significantly increase capital expenditures and operating costs or reduce demand for the Company's services. If the Company’s utility and pipeline operations do not receive timely and full recovery of GHG emission compliance costs from customers, then such costs could adversely impact the results of operations and cash flows. Significant reductions in demand for the Company's services as a result of increased costs or emissions limitations could also adversely impact the results of operations and cash flows.

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Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the potential financial impact on its operations. In addition, any increased focus on climate change and stricter regulatory requirements may result in the Company facing adverse reputational risks associated with certain of its operations producing GHG emissions. There have also been efforts to discourage the investment community from investing in equity and debt securities of companies engaged in fossil fuel related business and pressuring lenders to limit funding to such companies. Additionally, some insurance carriers have indicated an unwillingness to insure assets and operations related to certain fossil fuels. If the Company is unable to satisfy the climate-related expectations of certain stakeholders, the Company may suffer reputational harm, which may cause its stock price to decrease or difficulty in accessing the capital or insurance markets. Such efforts, if successfully directed at the Company, could increase the costs of or access to capital or insurance and interfere with business operations and ability to make capital expenditures.

Ownership of the Company's Common Stock Risks

Statutory, legal, and regulatory requirements may limit another party's ability to acquire the Company or impose conditions on an acquisition of or by the Company.

Approval from federal and state regulatory agencies would be needed for acquisition of the Company, as well as for certain acquisitions by the Company. The approval process could be lengthy and the outcome uncertain, which may deter potential acquirers from approaching the Company or impact the Company's ability to pursue acquisitions.

The Company’s amended and restated certificate of incorporation, bylaws, and Delaware law each contain provisions that may discourage or delay an acquisition of the Company, which could decrease the trading price of the Company’s common stock.

The Company’s amended and restated certificate of incorporation, bylaws, and Delaware law each contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids more expensive to the acquirers and to encourage prospective acquirers to negotiate with the Company’s board of directors rather than attempt a hostile takeover of the Company. These provisions include rules regarding how stockholders may present proposals or nominate directors for election at stockholder meetings and the right of the Company’s board of directors to issue preferred stock without stockholder approval. In addition, Section 203 of the Delaware General Corporation Law may discourage, delay, or prevent a change in control of the Company. Any delay or prevention of a change of control or change in management that stockholders might otherwise consider to be favorable could cause the market price of the Company’s common stock to decline.

The Company's stock price may be volatile and the value of its common stock may decline.

The market price of the Company’s common stock may be volatile and may fluctuate or decline as a result of a variety of factors, some of which are beyond its control, including without limitation actual or anticipated fluctuations in its financial condition or results of operations; variance in its financial performance from the expectations of securities analysts which may result in securities analysts issuing unfavorable research about the Company; changes in the Company’s projected operating and financial results; significant data breaches; material litigation; future sales of the Company’s common stock by the Company or its stockholders, or the perception that such sales may occur; changes in senior management or key personnel; the trading volume of the Company’s common stock; changes in the anticipated future size and growth rate of its service territories; and general macroeconomic, geopolitical, and market conditions beyond the Company’s control.

Broad market and industry fluctuations, as well as general economic, political, regulatory, and market conditions, such as recessions, or interest rate changes, may also negatively affect the market price of the Company’s common stock. In the past, companies that have experienced volatility in the market price of their securities have been subject to securities class action litigation. The Company may be the target of this type of litigation in the future, which could result in substantial expenses and divert management’s attention.

In addition, the Company enters into equity FSAs from time to time under which the Company may, at its election and subject to customary conditions, settle all or a portion of the agreements by physical delivery of shares of its common stock in exchange for cash proceeds, net share settlement, or cash settlement. Equity FSA's can expose the Company to risks associated with fluctuations in the market price of its common stock and certain forward-price adjustment factors, which may reduce the net proceeds the Company ultimately receives or increase its settlement obligation. These agreements also expose the Company to counterparty and timing risks and there can be no assurance that settling the agreements will ultimately prove to be beneficial to the Company's stockholders.

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The Company's inability to implement its long-term strategic plan may adversely affect future results.

The Company’s ability to successfully implement and execute its long-term strategic plan is dependent on many factors. The Company’s strategies may require significant capital investment and management attention. If the Company cannot successfully execute its strategic growth initiatives, its capital investment plan, or if the long-term plan does not adequately address the challenges or opportunities the Company faces, its financial condition and results of operations may be adversely affected. Additionally, failure to meet stockholder expectations, particularly with respect to financials, cost-cutting programs, operating margins, and earnings per share, could result in volatility in the market value of the Company’s stock.

The Company is a holding company and relies on cash from its subsidiaries to pay dividends.

The Company depends on earnings, cash flows and dividends from its subsidiaries to pay dividends on its common stock. Regulatory, contractual and legal limitations, as well as their capital requirements, affect the ability of the subsidiaries to pay dividends to the Company and thereby could restrict or influence the Company's ability or decision to pay dividends on its common stock, which could adversely affect the Company's stock price.

The Company may face risks associated with stockholder activism.

Publicly-traded companies are subject to campaigns by stockholders advocating corporate actions related to matters, such as corporate governance, operational practices, and strategic direction. The Company has, and may again in the future, become subject to such stockholder activity and demands. Such activities could interfere with its ability to execute its business plans, affect the allocation of capital, be costly and time-consuming, disrupt operations, and divert the attention of management, any of which could have an adverse effect on the Company’s business or stock price.

Other Risks

The Company's businesses are seasonal and subject to weather conditions that could adversely affect the Company's operations, revenues, and cash flows.

The Company's results of operations could be affected by changes in the weather. Weather conditions influence the demand for electricity and natural gas and affect the price of energy commodities. Utility operations have historically generated lower revenues when weather conditions are cooler than normal in the summer and warmer than normal in the winter, particularly in jurisdictions that do not have weather normalization mechanisms in place. Where weather normalization mechanisms are in place, there is no assurance the Company will continue to receive such regulatory protection from adverse weather in future rates.

Adverse weather conditions, which have occurred and may reoccur, such as heavy or sustained rainfall or snowfall, droughts, storms, wind and colder weather may affect ongoing operation and maintenance and construction activities for the electric and natural gas transmission and distribution businesses. In addition, severe weather can be destructive, causing outages and property damage, which could require additional remediation costs. As a result, unusual or adverse weather conditions could negatively affect the Company's results of operations, financial position and cash flows.

Competition exists in all of the Company's businesses.

The Company's businesses are subject to competition. The electric utility and natural gas businesses experience competitive pressures as a result of consumer demands, technological advances, and other factors. The pipeline business competes with several pipelines for access to natural gas supplies and for transportation and storage business. New acquisition opportunities are subject to competitive bidding environments which impact prices the Company must pay to successfully acquire new properties and acquisition opportunities to grow its business. The Company's failure to effectively compete could negatively affect the Company's results of operations, financial position and cash flows.

The Company's operations may be negatively affected if it is unable to obtain, develop, and retain key personnel and skilled labor forces.

The Company must attract, develop and retain executive officers and other professional, technical and skilled labor forces with the skills and experience necessary to successfully manage, operate and grow the Company's businesses.

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Due to the changing workforce dynamics and an insufficient number of qualified applicants to replace skilled employees as they retire and remote work opportunities, among other things, competition for these employees is high. In some cases competition for these employees is on a regional or national basis. At times of low unemployment, it can be difficult for the Company to attract and retain qualified and affordable personnel. A shortage in the supply of personnel creates competitive hiring markets, increased labor expenses, decreased productivity and potentially lost business opportunities to support the Company's operating and growth strategies. The Company is subject to risks associated with labor disputes or prolonged negotiation processes, which could disrupt operations and increase costs. Additionally, if the Company is unable to hire employees with the requisite skills, the Company may be forced to incur significant training expenses. As a result, the Company's ability to maintain productivity, relationships with customers, competitive costs, and quality services is limited by the ability to employ, retain and train the necessary personnel and could negatively affect the Company's results of operations, financial position and cash flows.

Costs related to obligations under a MEPP could have a material negative effect on the Company's results of operations and cash flows.

An operating subsidiary of the Company participates in a MEPP for employees represented by a union. The Company is required to make contributions to this plan in amounts established under the collective bargaining agreement between the operating subsidiary and the union. The Company may be obligated to increase its contribution to the plan if it becomes underfunded and is classified as being in endangered, seriously endangered or critical status as defined by the Pension Protection Act of 2006, or if other participating employers withdraw from the plan and are unable to contribute sufficient amounts. The amount and timing of any increase in the Company's required contributions may depend upon one or more factors, including the outcome of collective bargaining; actions taken by the trustee; actions taken by the plan's other participating employers; the industry; future determinations of plan status; and laws and regulations. The Company could experience increased operating expenses as a result of required contributions to the MEPP, which could have an adverse effect on the Company's results of operations, financial position or cash flows. In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from the plan, exiting a market in which it does business with a union workforce or upon termination of a plan. The Company could also incur an additional withdrawal liability if its withdrawal from the plan is determined by that plan to be part of a mass withdrawal.

Technology disruptions or cyberattacks could adversely impact the Company's operations.

The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information technology and operation technology systems, including disaster recovery and backup systems and network infrastructure. These systems may be vulnerable to physical and cybersecurity failures or unauthorized access, due to hacking, human error, theft, sabotage, malicious software, ransomware, third-party compromise, acts of terrorism, acts of war, acts of nature or other causes. Emerging artificial intelligence driven threats, such as biased outputs, artificial intelligence assisted phishing, deepfakes, and malicious use of generative artificial intelligence could further increase cybersecurity and operational risk.

Should a compromise or system failure occur, interdependencies to technology may disrupt the Company's ability to fulfill critical business functions. This may include interruption of electric generation, transmission and distribution facilities, natural gas storage and pipeline facilities, any of which could adversely affect the Company's reputation, business, cash flows and results of operations or subject the Company to legal or regulatory liabilities and increased costs. Litigation expenses and damages for such an event can be significant. Additionally, the Company's electric generation and transmission systems and natural gas pipelines are part of interconnected systems with other operators’ facilities; therefore, a cyber-related disruption in another operator’s system could negatively impact the Company's business.

The Company’s accounting systems and its ability to collect information and invoice customers for services could be disrupted. If the Company’s operations are disrupted, it could result in decreased revenues and remediation costs that could adversely affect the Company's results of operations and cash flows.

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The Company is subject to cybersecurity and privacy laws, regulations and security directives of many government agencies, including TSA, FERC, NERC, and state regulatory bodies. NERC issues comprehensive regulations and standards surrounding the security of bulk power systems and continually updates these requirements, as well as establishing new requirements with which the utility industry must comply. TSA cybersecurity directives for pipeline operators introduces heightened compliance obligations. As these regulations evolve, the Company may experience increased compliance costs and may be at higher risk for violating these standards. Experiencing a cybersecurity incident could cause the Company to be non-compliant with applicable laws and regulations, causing the Company to incur costs related to legal claims, proceedings and regulatory fines or penalties. Additionally, costs incurred to comply with cybersecurity directives or to remediate a cybersecurity incident may not be fully recoverable through customer rates. The SEC has adopted rules that require the Company to provide disclosures around cybersecurity risk management, strategy, and governance, as well as disclose the occurrence of material cybersecurity incidents. These rules may also require the Company to report a cybersecurity incident before the Company has been able to fully assess its impact or remediate the underlying issue. Efforts to comply with such reporting requirements could divert management's attention from the Company's incident response and could potentially reveal system vulnerabilities to threat actors. Failure to timely report incidents under these or other similar rules could also result in monetary fines, sanctions or subject the Company to other forms of liability. This regulatory environment is increasingly challenging and may present material obligations and risks to the Company's business, including significantly expanded compliance burdens, costs, and enforcement risks.

The Company, through the ordinary course of business, requires access to sensitive customer, supplier, employee and Company data. A breach of the Company's systems could compromise sensitive data and could go unnoticed for some time. Such an event could result in negative publicity and reputational harm, remediation costs, legal claims and fines that could have an adverse effect on the Company's financial results. Third-party service providers that perform critical business functions for the Company or have access to sensitive information within the Company also may be vulnerable to security breaches and information technology risks that could adversely affect the Company.

The Company’s information systems experience ongoing and often sophisticated cyberattacks by a variety of sources with the apparent aim to breach the Company's cyber-defenses. The Company may face increased cyber risk due to the increased use of employee-owned devices, and work from home arrangements. Such incidents could have a material adverse effect in the future as cyberattacks continue to increase in frequency and sophistication. The Company is continuously reevaluating the need to upgrade and/or replace systems and network infrastructure. These upgrades and/or replacements could adversely impact operations by imposing substantial capital expenditures, creating delays or outages, or experiencing difficulties transitioning to new systems. System disruptions, if not anticipated and appropriately mitigated, could adversely affect the Company.

Artificial intelligence presents challenges that can impact the Company's business by posing security risks to confidential or proprietary information and personal data.

The use of artificial intelligence, combined with an uncertain regulatory environment, may result in reputational harm, liability, or other adverse consequences to business operations. The Company has, and may again in the future, adopt and integrate certain artificial intelligence tools into its systems for specific use cases. The Company’s vendors and third-party partners may incorporate artificial intelligence tools into their offerings with or without disclosing this use to the Company. The providers of these artificial intelligence tools may not meet existing or rapidly evolving regulatory or industry standards concerning privacy and data protection, which may result in a loss of intellectual property or confidential information and/or cause harm to the Company’s reputation and the public perception of the effectiveness of its security measures. Further, bad actors around the world use increasingly sophisticated methods, including artificial intelligence, to engage in illegal activities involving the theft and misuse of personal information, confidential information, and intellectual property. Any of these outcomes could damage the Company’s reputation, result in the loss of valuable property and information and adversely impact its business.

Pandemics may have a negative impact on the Company's business operations, revenues, results of operations, liquidity, and cash flows.

Pandemics have disrupted national, state and local economies in the past and may again in the future. To the extent pandemics adversely impact the Company's businesses, operations, revenues, liquidity or cash flows, they could also have a heightened effect of other risks. The degree to which pandemics impact the Company depends on, among other things, federal, state and local mandates, actions taken by governmental authorities, availability, timing and effectiveness of vaccines being administered, and the pace and extent to which the economy recovers and operates under normal market conditions.

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Separation Risks

If the completed separations of Knife River or Everus, together with certain related transactions, were to fail to qualify as transactions that are generally tax-free for U.S. federal income tax purposes, the Company and its stockholders could be subject to significant tax liabilities.

The Company completed the separations of Knife River and Everus on May 31, 2023, and October 31, 2024, respectively. In connection with the completed separations, the Company received private letter rulings from the IRS and opinion(s) of outside counsel regarding the qualification of certain elements of the separations and distributions under Section 355(a) of the Code. Notwithstanding prior receipt of IRS private letter rulings and opinion(s) of tax advisors, the IRS could determine that the completed distributions and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions, or undertakings upon which the IRS private letter rulings or the opinion(s) of tax advisors were based are false or have been violated. In addition, neither the IRS private letter rulings nor opinion(s) of tax advisors will address all of the issues that are relevant to determining whether the distributions, together with certain related transactions, qualifies as transactions that are generally tax-free for U.S. federal income tax purposes. Further, opinion(s) of tax advisors represent the judgment of such tax advisors and are not binding on the IRS or any court, and the IRS or a court may disagree with the conclusions in the opinion(s) of tax advisors. Accordingly, notwithstanding receipt by the Company of the IRS private letter rulings and the opinion(s) of tax advisors, there can be no assurance that the IRS will not assert that the distributions and/or certain related transactions do not qualify for tax-free treatment for U.S. federal income tax purposes or that a court would not sustain such a challenge. In the event the IRS were to prevail in such challenge, the Company and its stockholders could be subject to significant U.S. federal income tax liability.

Item 1B. Unresolved Staff Comments

The Company has no unresolved comments with the SEC.

Item 1C. Cybersecurity

Risk Management and Strategy

Overall Risk Management

The Company has implemented a cyber risk management program to help ensure that the Company's electronic information and information systems are protected from various threats. The cyber risk management program is maintained as part of the Company's overall governance, ERM program and compliance program. The Company's information systems experience ongoing and often sophisticated cyberattacks by a variety of sources with the apparent aim to breach the Company's cyber-defenses. The Company has and may continue to face increased cyber risk due to the increased use of employee-owned devices and work from home arrangements. The Company is continuously reevaluating the need to upgrade and/or replace systems and network infrastructure. These upgrades and/or replacements could adversely impact operations by imposing substantial capital expenditures, creating delays or outages, or experiencing difficulties transitioning to new systems. System disruptions, if not anticipated and appropriately mitigated, could adversely affect the Company. The Company continually assesses risks from cybersecurity threats and adapts and enhances its controls accordingly.

Risks from Cybersecurity Threats

Any risks from previous cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected or are reasonably likely to materially affect the Company's business, financial condition, or results of operations. Such risks and incidents could have a material adverse effect in the future as cyberattacks continue to increase in frequency and sophistication. The Company also has cyber event related insurance.

Employee Cybersecurity Training

The Company provides ongoing cybersecurity training and compliance programs to facilitate education for employees who may have access to the Company's data and critical systems. Employee phishing tests are conducted on a monthly basis.

Engage Third-parties on Risk Management

Periodic external reviews, including penetration tests and security framework assessments, are conducted by auditors, external assessors, and/or consultants to assess and ensure compliance with the Company’s information security programs and practices. Internal and external auditors assess the Company’s information technology general controls on an annual basis.

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Oversee Third-party Risk

The Company has implemented a third-party management risk program to help monitor and reduce risks associated with the Company's vendors, which includes processes such as completing due diligence on third party service providers before engaging with them for their services; assessing the third party’s cybersecurity posture by reviewing audit reports of the third party, completing cyber questionnaires, and reviewing applicable certification; including cybersecurity contractual language in contracts to limit risk; and monitoring and reassessing third party’s to ensure ongoing compliance with their cybersecurity obligations.

Physical Security

The Company safeguards assets through a standard physical security design process, including access controls, surveillance and monitoring, perimeter security controls, data center security, and incident response and reporting controls.

Operational Technology

The Company has operation technology, consisting of the hardware and software that monitors and controls devices, processes, and infrastructure related to the Company's operational assets. Security protocols for the Company's operational technology follow applicable NERC, FERC and TSA regulations and security directives.

Other Risk Factors

Notwithstanding the breadth of the Company's information security program, the Company may be unsuccessful in preventing or mitigating a cybersecurity event that could have a material adverse impact. See Item 1A – Risk Factors – Other Risks – Technology disruptions or cyberattacks could adversely impact the Company's operations.

Governance

Board of Directors Oversight

The Company's board of directors, as a whole and through its committees, has responsibility for oversight of risk management. In its risk oversight role, the board of directors has the responsibility to satisfy itself that the risk management processes designed and implemented by management are adequate for identifying, assessing, and managing risk. The audit committee of the board of directors of the Company is responsible for oversight of risks from cybersecurity threats.

Management's Role Managing Risk

The Company's CIO plays a large role in informing the audit committee of the board of directors on cybersecurity risks. The audit committee of the board of directors receives presentations and reports from the CIO on cybersecurity related issues which include information security, technology risks and risk mitigation programs regularly at the quarterly board meetings. In addition to scheduled meetings, the CIO and audit committee of the board of directors maintain an ongoing dialogue regarding emerging or potential cybersecurity risks.

Cybersecurity Incident Response

The Company has an incident response plan to identify, protect, detect, respond to, and recover from cybersecurity threats and incidents that is also tested on an annual basis. The incident response plan is updated based on results of the test or as new cyber related developments occur. The CIO, executive leadership which includes the chief executive officer, chief financial officer, chief accounting officer, chief legal officer, and SEC financial reporting department employees, and the board of directors are notified of any material cybersecurity incidents through a defined escalation process. The defined escalation process is a risk-based process that specifies who is to be contacted and when at each risk level.

Monitor, Manage, and Safeguard Against Cybersecurity Incidents and Risks

The Company's CIO, along with its director of cybersecurity and a designated security team of professionals, are responsible for assessing and managing risks as well as developing and implementing policies, procedures, and practices based on the range of threats faced by the Company. There are processes around access management, data security, encryption, asset management, secure system development, security operations, network and device security to provide safeguards from a cybersecurity incident along with continual monitoring of various threat intelligence feeds.

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Cyber Risk Management Personnel

The Company's director of cybersecurity reports to the CIO and the CIO reports directly to the Company's chief executive officer. The Company's CIO holds both a bachelor's and master's degree in business administration with over 25 years of information technology experience in the energy and utilities business. The director of cybersecurity has a bachelor’s degree in computer information systems, over 25 years of information security experience, and holds certified information systems security professional and certified risk and information systems control certifications. The other members of information technology director level leadership also responsible for managing cybersecurity risks have degrees including Bachelor of Computer Information Systems, information systems management, electronics, electrical engineering, business administration, and accounting, along with certified information systems auditor certification and a cybersecurity fundamentals certificate.

Cyber Risk Oversight Committee

Additionally, in 2014 the board of directors established CyROC to provide executive management and the audit committee of the board of directors with analyses, appraisals, recommendations and pertinent information concerning cyber defense of the Company's electronic information, information technology and operation technology systems. The CyROC is responsible for guiding the Company's comprehensive cybersecurity policies and oversight of cybersecurity risks. The CyROC is chaired by the Company's CIO and is comprised of members such as the chief financial officer, information technology leaders, internal auditors, and other leaders from across the Company.

Item 2. Properties

The Company’s material properties include electric generating facilities, electric transmission and distribution lines, natural gas transmission and distribution lines, natural gas storage lines and underground natural gas storage fields, which are described in Item 1 - Business under Electric, Natural Gas Distribution and Pipeline.

Item 3. Legal Proceedings

SEC regulations require the Company to disclose certain information about proceedings arising under federal, state or local environmental provisions if the Company reasonably believes that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to SEC regulations, the Company has adopted a threshold of $1.0 million for purposes of determining whether disclosure of any such proceedings is required.

For information regarding legal proceedings required by this item, see Item 8 - Note 17, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company's common stock is listed on the NYSE under the symbol "MDU."

As of February 13, 2026, the Company's common stock was held by approximately 8,200 stockholders of record.

As a pure-play regulated energy delivery business, the Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 88-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend. The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by agreements governing the Company's indebtedness, federal and state laws, and applicable regulatory limitations. For more information on factors that may limit the Company's ability to pay dividends, see Item 8 - Note 11.

The following table includes information with respect to the Company's purchase of equity securities:

ISSUER PURCHASES OF EQUITY SECURITIES
Period			Total Number of Shares (or Units) Purchased (1)			Average Price Paid per Share (or Unit)			Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)			Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
October 1 through October 31, 2025			—			—			—			—
November 1 through November 30, 2025			51,651			$20.61			—			—
December 1 through December 31, 2025			—			—			—			—
Total			51,651			$20.61			—			—

(1)    Represents MDU original issue shares of common stock in connection with annual stock grants made to the Company's non-employee directors.

(2)    Not applicable. The Company does not currently have in place any publicly announced plans or programs to repurchase equity securities.

Item 6.

Reserved.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The Company generates, transmits and distributes electricity and provides natural gas distribution, transportation and storage services. Through a strategy focusing on its "CORE," the Company strives to deliver superior value and achieve industry-leading performance as a pure-play regulated energy delivery company, while pursuing organic growth opportunities. The Company's "CORE" strategy prioritizes customers and communities, operational excellence, returns focused initiatives and an employee driven culture.

Strategic Initiatives On May 31, 2023, the Company completed the separation of Knife River, its construction materials and contracting business, resulting in Knife River becoming an independent, publicly-traded company. The Company's board of directors approved the distribution of approximately 90 percent of the issued and outstanding shares of Knife River to the Company's stockholders. Stockholders of the Company received one share of Knife River common stock for every four shares of the Company's common stock held on May 22, 2023, the record date for the distribution. The Company retained approximately 10 percent or 5.7 million shares of Knife River common stock immediately following the separation, which were disposed of in a tax-free exchange in November 2023. The separation of Knife River was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

On October 31, 2024, the Company completed the separation of Everus, its construction services business, resulting in Everus becoming an independent, publicly-traded company. The Company's board of directors approved the distribution of all the outstanding shares of Everus common stock to the Company's stockholders. Stockholders of the Company received one share of Everus common stock for every four shares of the Company's common stock held as of the close of business on October 21, 2024, the record date for the distribution. The separation of Everus was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

The Company incurred costs in connection with the strategic initiatives in 2023, 2024 and 2025, as noted in the Business Segment Financial and Operating Data section.

One Big Beautiful Bill Act On July 4, 2025, the reconciliation bill was enacted into law, extending key provisions of the 2017 Tax Cuts and Jobs Act while scaling back clean energy tax incentives of the IRA. Changes in tax laws may affect recorded deferred tax assets and deferred tax liabilities or the Company's effective tax rates in the future. The Company has evaluated new legislation, and it does not expect a material impact to the consolidated financial statements or ongoing tax rate as a result of this legislation.

Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, interest rates, changes in tariffs, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business. The Company has observed supply chain improvements in lead times for certain commodities. The Company has experienced impacts related to the changes in tariffs and continues to navigate the current environment and monitor the future for impacts that could occur. For more information on possible impacts to the Company's businesses, see the Outlook for each segment below and Item 1A - Risk Factors.

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Consolidated Earnings Overview

The following table summarizes the contribution to the consolidated income by each of the Company's business segments.

Years ended December 31,			2025			2024			2023
			(In millions, except per share amounts)
Electric			$	64.9		$	74.8		$	71.6
Natural gas distribution			56.1			46.9			48.5
Pipeline			68.2			68.0			47.4
Other			2.2			(8.6)			162.6
Income from continuing operations			191.4			181.1			330.1
Discontinued operations, net of tax			(1.0)			100.0			84.6
Net income			$	190.4		$	281.1		$	414.7
Earnings per share - basic:
Income from continuing operations			$	.94		$	.89		$	1.62
Discontinued operations, net of tax			(.01)			.49			.42
Earnings per share - basic			$	.93		$	1.38		$	2.04
Earnings per share - diluted:
Income from continuing operations			$	.93		$	.88		$	1.62
Discontinued operations, net of tax			—			.49			.41
Earnings per share - diluted			$	.93		$	1.37		$	2.03

The Company completed the separations of Knife River on May 31, 2023, its former construction materials and contracting segment, and of Everus on October 31, 2024, its former construction services segment, into new independent publicly-traded companies. As a result of these separations, the historical results of operations for Knife River and Everus are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the Company, which did not meet the criteria for discontinued operations and are reflected in Other. Also included in discontinued operations are certain strategic initiative costs associated with the separations of Knife River and Everus. Other includes activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023.

Results of Operations The Company's discussion and analysis for the year ended December 31, 2025 compared to 2024 is included herein. For discussion and analysis for the year ended December 31, 2024 compared to 2023 refer to Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025.

2025 compared to 2024 The Company's consolidated earnings decreased $90.7 million primarily due to the absence of income from discontinued operations in 2025, partially offset by increased earnings at the natural gas distribution business.

•Earnings at the electric business were impacted by higher operation and maintenance expense, primarily increased payroll-related costs, contract services related to Coyote Station planned outage-related costs, software expense, which include certain costs associated with services provided under the Transition Services Agreement with Everus that are recovered in other income, and insurance expense. Partially offsetting the increased operation and maintenance expense were higher retail sales revenue and retail sales volumes, partially driven by a data center near Ellendale, North Dakota.

•Increased earnings at the natural gas distribution business was largely the result of higher retail sales revenue, driven largely by rate relief in Washington, Montana, South Dakota and Wyoming. The increase was partially offset by higher operation and maintenance expense, primarily higher insurance expense, payroll-related costs, and software expense, which include certain costs associated with services provided under the Transition Services Agreement with Everus that are recovered in other income.

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•The pipeline's slight earnings increase was driven by growth projects placed in service throughout 2024 and in late 2025 and customer demand for short-term firm natural gas transportation contracts. Higher use of the company's interruptible natural gas transportation services further drove the increase. The increase was partially offset by higher operation and maintenance expense primarily attributable to payroll-related costs. The increase was further offset by the absence of $1.5 million, net of tax proceeds received in 2024 from a customer settlement as well as the absence of a benefit from an adjustment related to the Company's effective state income tax rate change. The business also incurred higher depreciation expense due to growth projects placed in service, as previously discussed, and higher property taxes in Montana.

•Other was impacted by the absence of the income from discontinued operations in 2025. Partially offsetting the decrease was lower operation and maintenance expense, largely a result of corporate overhead costs classified as continuing operations allocated to the construction services business in 2024, which are not included in Other in 2025.

A discussion of key financial data from the Company's business segments follows.

Business Segment Financial and Operating Data

The following are key financial and operating data for each of the Company's business segments. Highlights of key growth strategies, projections and certain assumptions for the Company and its subsidiaries, and other matters concerning the Company's business segments are included below. Many of these highlighted points are "forward-looking statements." For more information, see Part I - Forward-Looking Statements. There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Item 1A - Risk Factors. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's projections.

For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Item 8 - Note 14.

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Electric and Natural Gas Distribution

Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Item 1 - Business. Both segments strive to be top performing utilities and provide safe, reliable, competitively priced and environmentally responsible energy services to customers. The segments are focused on cultivating organic growth while managing operating costs and monitoring opportunities for these segments to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation, transmission and distribution, and natural gas systems. The continued efforts to create operational improvements and efficiencies across both segments promotes the Company's business integration strategy. The primary factors that impact the results of these segments are the ability to earn authorized rates of return; weather; climate change laws, regulations and initiatives; competitive factors in the energy industry; population growth; and economic conditions in the segments' service areas.

The electric and natural gas distribution segments are subject to extensive regulation in the jurisdictions where they conduct operations with respect to costs, timely recovery of investments and permitted returns on investment. The Company is focused on modernizing utility infrastructure to meet the varied energy needs of both its customers and communities while working to deliver safe, reliable, affordable and environmentally responsible energy. The segments continue to invest in facility upgrades to be in compliance with existing and known future regulations. To assist in the reduction of regulatory lag in obtaining revenue increases to align with increased investments, tracking mechanisms have been implemented in certain jurisdictions. The Company also seeks rate adjustments for operating costs and capital investments, as well as reasonable returns on investments not covered by tracking mechanisms. For more information on the Company's tracking mechanisms and recent rate cases, see Item 1 - Business and Item 8 - Note 6.

These segments are also subject to extensive regulation related to certain operational and environmental compliance, cybersecurity, permit terms and system integrity. Both segments are faced with the ongoing need to actively evaluate cybersecurity processes and procedures related to its transmission and distribution systems for opportunities to further strengthen its cybersecurity protections. There have been cyber and physical attacks within the energy industry on infrastructure, such as substations, and the Company continues to evaluate the safeguards implemented to protect its electric and natural gas utility systems. Implementation of enhancements and additional requirements to protect the Company's infrastructure is ongoing.

To date, many states have enacted, and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns. MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to growth in the data center industry. Montana-Dakota filed its 2024 IRP with the NDPSC in July 2024. With MISO's filed changes in resources adequacy at FERC and the adoption of direct loss of load accreditation for generation resources around riskiest hours on the system versus peak load hours, Montana-Dakota identified the need to add additional capacity resources to its system by 2028 versus 2034 as identified in its previous IRP. The Company previously executed a PPA for 150 MW of output from Badger Wind Farm, which included the option to purchase a 49 percent ownership interest. With the closing now complete, the PPA has been reduced to 27.5 MW. The ownership stake in Badger Wind Farm reduced the Company's capacity and energy purchase requirements as identified in the 2024 IRP. The Company will continue to monitor the progress of these changes, including the impacts associated with the implementation of MISO's direct loss of load accreditation in 2028, and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures.

Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather, as well as impacts associated with commercial and industrial slow-downs, including economic recessions, and energy efficiencies. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among residential and commercial customers. Average consumption among both electric and natural gas customers has tended to decline as more efficient appliances and furnaces are installed, and as the Company has implemented conservation programs. Natural gas weather normalization and decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins, as further discussed in Item 1 - Business.

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In the second half of 2023, electric fuel and purchased power prices increased across Montana-Dakota's integrated system and remained elevated through January 2024. This was caused by transmission congestion in northwest North Dakota due to delays in additional SPP transmission line build-out, as well as additional load growth in the Bakken region. To assist in the recovery of the higher electric fuel and purchased power costs, Montana-Dakota filed waiver requests with the NDPSC and SDPUC, deferring the increased costs to the annual fuel clause adjustment. In Montana, the waiver request is filed monthly and was unopposed by the MTPSC. Effective April 1, 2024, as approved by the NDPSC, Montana-Dakota started recovery in North Dakota of these increased costs over a period of two years rather than one year. In South Dakota and Montana, Montana-Dakota recovered these costs over a one-year period effective July 1, 2024. In July 2025, the NDPSC approved Montana-Dakota's request to defer external legal expenses related to this congestion litigation and record those deferred expenses into a regulatory asset. Montana-Dakota and MISO each filed a petition for review of the FERC decision with the Eighth Circuit with a decision expected in the first half of 2026.

The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures have moderated but costs for goods and services remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Item 1A - Risk Factors.

The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to higher costs and long lead times for equipment, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project. The route permit for the JETx line was filed with the NDPSC in August 2025. JETx is expected to be placed in service at the end of 2028.

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Earnings overview - The following information summarizes the performance of the electric segment.

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Operating revenues			$	438.3		$	414.5		$	401.2					5.7		%	3.3		%
Operating expenses:
Electric fuel and purchased power			159.0			141.2			134.8						12.6		%	4.7		%
Operation and maintenance			111.3			95.0			92.7						17.2		%	2.5		%
Depreciation and amortization			69.6			66.5			64.2						4.7		%	3.6		%
Taxes, other than income			18.8			17.6			16.7						6.8		%	5.4		%
Total operating expenses			358.7			320.3			308.4						12.0		%	3.9		%
Operating income			79.6			94.2			92.8						(15.5)		%	1.5		%
Other income			7.4			8.2			5.8						(9.8)		%	41.4		%
Interest expense			31.7			30.0			28.0						5.7		%	7.1		%
Income before income taxes			55.3			72.4			70.6						(23.6)		%	2.5		%
Income tax benefit			(9.6)			(2.4)			(1.0)						300.0		%	140.0		%
Net income			$	64.9		$	74.8		$	71.6					(13.2)		%	4.5		%

Operating statistics
			2025			2024			2023
Revenues (millions)
Retail sales:
Residential			$	136.7		$	139.9		$	134.1
Commercial			179.0			165.8			164.1
Industrial			37.8			42.3			42.3
Other			7.4			7.8			7.1
			360.9			355.8			347.6
Other			77.4			58.7			53.6
			$	438.3		$	414.5		$	401.2
Volumes (million kWh)
Retail sales:
Residential			1,191.1			1,159.5			1,180.2
Commercial			2,820.5			2,474.5			2,350.5
Industrial			485.7			528.9			583.7
Other			81.8			81.6			81.8
			4,579.1			4,244.5			4,196.2
Average cost of electric fuel and purchased power per kWh			$	.026		$	.025		$	.024
Cooling degree days (% warmer (colder) than prior year)1
Montana			(5.4)		%	(0.7)		%	(1.0)		%
North Dakota			(6.9)		%	(2.2)		%	(5.4)		%
South Dakota			16.8		%	(27.0)		%	(9.8)		%
Wyoming			(24.8)		%	46.1		%	(26.4)		%
1Cooling degree days are a measure of the energy demand for cooling.

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2025 compared to 2024 Electric earnings decreased $9.9 million as a result of:

•Revenue increased $23.8 million.

◦Largely attributable to:

▪Higher fuel and purchased power costs of $17.8 million recovered in customer rates and offset in expense, as described below.

▪Higher net transmission revenue of $3.5 million, including data center revenue.

▪Higher retail sales volumes of $1.2 million, driven primarily by higher residential volumes, largely due to colder weather in the first quarter of the year, and higher commercial volumes from the data center as further discussed in the Outlook section.

◦Partially offset by lower renewable tracker revenues, partially associated with higher production tax credits offset in income tax benefit, as described below.

•Electric fuel and purchased power increased $17.8 million, largely the result of higher retail sales volumes and higher commodity prices.

•Operation and maintenance increased $16.3 million.

◦Largely the result of:

▪Higher payroll-related costs of $5.7 million.

▪Higher contract services related to Coyote generating station planned outage-related costs of $3.5 million.

▪Increased software expense of $3.2 million.

▪Higher insurance expense.

◦Also reflected are higher costs associated with services provided to Everus as part of the transition services agreement, offset in other income, as described below. The transition services are expected to be complete as of March 2026.

•Depreciation and amortization increased $3.1 million, largely due to increased property, plant and equipment balances, as a result of transmission projects placed in service to improve reliability and update aging infrastructure.

•Taxes, other than income increased $1.2 million, largely as a result of higher property tax, primarily in Montana.

•Other income decreased $800,000, primarily due to lower interest income related to a data center project and lower regulatory deferral balances, partially offset by higher transition services agreement income, as described above.

•Interest expense increased $1.7 million, largely the result of lower AFUDC due to lower interest rates and average CWIP balances.

•Income tax benefit increased $7.2 million, largely due to lower income before income taxes, and higher production tax credits of $2.5 million driven by higher wind production and wind farm repowers.

44 MDU Resources Group, Inc. Form 10-K

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Earnings overview - The following information summarizes the performance of the natural gas distribution segment.

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Operating revenues			$	1,283.5		$	1,201.1		$	1,287.5					6.9		%	(6.7)		%
Operating expenses:
Purchased natural gas sold			746.3			699.3			805.1						6.7		%	(13.1)		%
Operation and maintenance			241.2			231.2			219.7						4.3		%	5.2		%
Depreciation and amortization			105.0			102.0			95.3						2.9		%	7.0		%
Taxes, other than income			81.5			76.0			75.2						7.2		%	1.1		%
Total operating expenses			1,174.0			1,108.5			1,195.3						5.9		%	(7.3)		%
Operating income			109.5			92.6			92.2						18.3		%	.4		%
Other income			15.8			25.5			20.8						(38.0)		%	22.6		%
Interest expense			59.6			63.2			57.6						(5.7)		%	9.7		%
Income before income taxes			65.7			54.9			55.4						19.7		%	(.9)		%
Income tax expense			9.6			8.0			6.9						20.0		%	15.9		%
Net income			$	56.1		$	46.9		$	48.5					19.6		%	(3.3)		%

Operating statistics
			2025			2024			2023
Revenues (millions)
Retail sales:
Residential			$	680.0		$	651.8		$	726.1
Commercial			423.9			400.8			441.2
Industrial			45.2			42.7			45.0
			1,149.1			1,095.3			1,212.3
Transportation and other			134.4			105.8			75.2
			$	1,283.5		$	1,201.1		$	1,287.5
Volumes (MMdk)
Retail sales:
Residential			65.8			67.2			69.3
Commercial			49.4			46.9			47.9
Industrial			5.0			5.4			5.4
			120.2			119.5			122.6
Transportation sales:
Commercial			1.9			1.9			1.9
Industrial			168.4			192.6			188.4
			170.3			194.5			190.3
Total throughput			290.5			314.0			312.9
Average cost of natural gas per dk			$	6.21		$	5.85		$	6.57
Heating degree days (% colder (warmer) than prior year)1
Idaho			(6.1)		%	(7.3)		%	(9.0)		%
Minnesota			12.8		%	(12.6)		%	(11.9)		%
Montana			4.5		%	(4.6)		%	(2.8)		%
North Dakota2			9.7		%	(9.9)		%	0.3		%
Oregon2			(1.2)		%	(4.3)		%	(5.5)		%
South Dakota2			4.0		%	(10.0)		%	(0.2)		%
Washington2			(5.2)		%	(0.2)		%	(8.5)		%
Wyoming			7.6		%	(9.8)		%	1.4		%
1Heating degree days are a measure of the daily temperature demand for energy for heating. 2Weather normalization or decoupling mechanisms are in place that minimize the weather impact.

MDU Resources Group, Inc. Form 10-K 45

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2025 compared to 2024: Natural gas distribution earnings increased $9.2 million as a result of:

•Revenue increased $82.4 million.

◦Primarily due to:

▪Higher purchased natural gas sold of $47.0 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.

▪Rate relief of $25.2 million, primarily in Washington, Montana, South Dakota and Wyoming.

▪Higher revenue-based taxes of $3.6 million, recovered in rates and offset in expense, as described below.

▪Higher conservation revenues of $3.5 million, offset in expense, as described below.

▪Higher basic service charges of $2.1 million due to customer growth.

▪Higher retail sales volumes of $2.0 million, which includes weather normalization and decoupling mechanism in certain jurisdictions, and higher volumes to commercial customer classes. This increase was largely offset by lower volumes to residential customer classes, largely due to warmer weather in certain jurisdictions.

•Purchased natural gas sold increased $47.0 million, primarily due to higher net environmental compliance costs of $38.1 million, commodity costs of $4.9 million and volumes of natural gas purchased of $4.0 million.

•Operation and maintenance increased $10.0 million.

◦ Largely due to:

▪Higher conservation-related costs, recovered in rates, as discussed above.

▪Higher costs associated with MAOP projects of $1.7 million.

▪Higher insurance expense.

▪Higher payroll-related costs of $1.5 million.

▪Higher software related expenses of $1.3 million.

◦Also reflected are higher costs associated with services provided to Everus as part of the transition services agreement, offset in other income, as described below. The transition services are expected to be complete as of March 2026.

•Depreciation and amortization increased $3.0 million, of which $6.6 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented from rate cases in Montana, North Dakota, Wyoming, Washington and Oregon of $2.9 million, and lower regulatory amortizations.

•Taxes, other than income increased $5.5 million, due to higher revenue-based taxes, as described above, and higher property taxes, largely in Montana and Washington.

•Other income decreased $9.7 million.

◦Primarily due to:

▪Lower interest on regulatory deferral balances, primarily lower purchased gas cost deferral balances.

▪The absence of $2.2 million of interest income associated with prior year renewable natural gas projects.

▪Higher pension expense of $1.4 million.

▪Lower returns of $500,000 on the Company's nonqualified benefit plans.

◦Offset in part by higher transition services agreement income, as described above.

•Interest expense decreased $3.6 million, largely due to lower long-term debt balances.

•Income tax expense increased $1.6 million, largely the result of higher income before income taxes, partially offset by lower permanent tax adjustments.

46 MDU Resources Group, Inc. Form 10-K

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Outlook In 2025, the utility business experienced rate base growth of 16.0 percent, which includes the purchase of its ownership stake in Badger Wind Farm. These segments grew rate base by 8.7 percent annually over the last five years on a compound basis and expects to invest approximately $2.5 billion of capital expenditures over the next five years. Operations are spread across eight states where the Company expects customer growth to be higher than the national average. In 2025 and 2024, these segments experienced retail customer growth of approximately 1.5 percent and 1.4 percent, respectively, and the Company expects customer growth to continue to average 1 percent to 2 percent per year. This customer growth, along with system upgrades and replacements needed to supply safe and reliable service, will require investments in new and replacement electric and natural gas systems.

These segments are exposed to energy price volatility and may be impacted by changes in oil and natural gas exploration and production activity. Rate schedules in the jurisdictions in which the Company's natural gas distribution segment operates contain clauses that permit the Company to file for rate adjustments for changes in the cost of purchased natural gas. Although changes in the price of natural gas are passed through to customers and have minimal impact on the Company's earnings, the natural gas distribution segment's customers may benefit through the Company's utilization of storage and fixed price contracts to help manage price volatility.

The EPA's GHG and mercury emissions standards finalized in May 2024 would have required additional pollution controls for Coyote Station to operate beyond 2031 and 2027, respectively. In April 2025, the EPA granted a two year extension for Coyote Station to add pollution controls to comply with the mercury emissions standard. In June 2025, the EPA proposed rules to repeal both the mercury emissions standard and the electric generation GHG emissions standard. If the rules go into effect, it could require owners of Coyote station to incur significant new costs. These costs could, dependent on determination by state regulatory commissions on approval to recover such costs from customers, negatively impact the Company's results of operations, financial position and cash flows. In December 2024, the EPA issued a final decision on the NDDEQ's Regional Haze state implementation plan, maintaining the proposed disapproval of the state's conclusion that no additional controls are warranted during this implementation period. The EPA did not issue a federal implementation plan in place of the state plan and would have two years from the state plan disapproval to either propose a federal plan or approve a new state plan. Coyote Station co-owners filed a petition for review with the Eighth Circuit in January 2025, challenging EPA's NDDEQ state plan disapproval, and in February 2025, filed a petition for reconsideration with the EPA, which was granted in April 2025. In June 2025, the Eighth Circuit granted a request by the EPA to continue to hold the petition of review proceeding in abeyance so that the EPA could review the previous administration's findings and actions. In March 2025, the EPA announced the agency is restructuring the regulations for implementing the Regional Haze Program. Further, in October 2025, the EPA released an advanced notice of proposed rulemaking seeking input on restructuring the program with the intent to streamline regulatory requirements for states' visibility improvement obligations. The Company is one of four owners of Coyote Station and cannot make a unilateral decision on the plant's future; therefore, the Company could be negatively impacted by decisions of the other owners. The joint owners continue to collaborate in analyzing data and weighing decisions that impact the plant and its employees as well as each company's customers and communities served.

In December 2025, the Company completed the acquisition of a 49 percent ownership interest in Badger Wind Farm and placed the asset in service. The completed transaction secures 122.5 MW of the project's total 250 MW generation capacity for the Company and follows the NDPSC's Advance Determination of Prudence and Certificate of Public Convenience and Necessity approvals, confirming the project is a prudent, cost-effective investment for customers. The Company previously executed a PPA for 150 MW of output from the project, which included the option to purchase the 49 percent ownership interest. With the closing now complete, the PPA has been reduced to 27.5 MW.

In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, which is the equivalent of about 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact other customers' power supply. An electric service agreement to serve an additional 350 MW data center load with Applied Digital in the Company's service territory was approved by the NDPSC. 100 MW of the additional data center load is expected to be fully online in the second quarter of 2026.

In August 2024, the Company filed a request with the SDPUC seeking approval on an electric service agreement to provide up to 50 MW of electricity to a data center near Leola, South Dakota. Construction of the data center and approval of the electric service agreement which had been pending development of new local siting requirements for data center loads by McPherson County in South Dakota, were effective August 5, 2025. Approval of the electric service agreement with the SDPUC is still pending filing an updated conditional use permit for the data center siting with McPherson County.

MDU Resources Group, Inc. Form 10-K 47

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The Infrastructure Investment and Jobs Act, commonly known as the Bipartisan Infrastructure Law, was enacted in the fourth quarter of 2021 designating funds for investments such as upgrades to electric and grid infrastructure, transportation systems, and electric vehicle infrastructure. In July 2025, the North Dakota Industrial Commission awarded the Company a grant award under the Grid Resilience and Innovative Partnerships Program, which is part of the Infrastructure Investment and Jobs Act. The funds from the award will be used by the Company to build a 46 kV transmission line that will connect the Merricourt Transmission Substation to a 46 kV line near Fredonia, North Dakota. In addition, the IRA provided new funding for clean energy programs. The Company continues to pursue various opportunities under the Grid Resilience and Innovative Partnerships Program, and is also pursuing a biogas property at the Knott Landfill site in Bend, Oregon which may qualify for an investment tax credit and clean fuel production credits as part of the IRA. As discussed previously, the Company has evaluated the OBBBA and does not expect a material impact as a result of this legislation.

Legislation and rulemaking The Company continues to monitor legislation and rulemaking related to clean energy standards that may impact its segments. Below are some of the specific legislative actions the Company is monitoring.

•In May 2024, the EPA published four final rules, three of which will impose stricter standards on GHG emissions from existing coal-fired and new natural gas-fired generation units, require a further reduction of mercury emissions from coal-fired generation units, and impose additional regulations around the storage and management of coal ash. In March 2025, the EPA announced reconsideration of the Electric Generation and Greenhouse Gas Rule, Mercury and Air Toxics Standards Rule, and Effluent Limitations Guidelines Rule. Comments on certain of these proposed rules were due in August 2025. If the rules were to remain as originally proposed and if the costs to comply with these rules are not fully recoverable from customers, they could have a material adverse effect on the Company's results of operations and cash flows.

•In February 2026, the EPA published a final rule that rescinded the 2009 Endangerment Finding and related standards for motor vehicle GHG emissions under the Clean Air Act. The final rule does not directly address or repeal GHG regulations for power plants and other non-motor vehicle sources. The Company is currently evaluating this rulemaking.

•In July 2024, the ODEQ published its proposed rules to create a new Climate Protection Program. The Oregon Environmental Quality Commission adopted the rules in November 2024. The Company intends to meet its obligations first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow.

•In Washington, the Climate Commitment Act was adopted by the Washington Legislature in 2021 and became effective in 2023. The Climate Commitment Act establishes a cap-and-invest program designed to reduce GHG emissions over time, while using auctioned allowances to fund state energy and environmental policy goals. The Company intends to meet its compliance obligations through a combination of energy efficiency measures, no-cost allowances, purchased allowances, and carbon offsets. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, the purchase of allowances could impact the Company's operating cash flow.

•The Washington SBCC in 2023 adopted residential and commercial building code amendments that will significantly limit the use of natural gas for space and water heating in new and retrofitted commercial and residential buildings. In May 2024, the Company filed a joint complaint seeking declaratory and injunctive relief under federal law against the Washington SBCC's adoption of the amended Washington State Energy Code. This complaint was dismissed by the federal district court. Petitioners have appealed this decision to the United States Court of Appeals for the Ninth Circuit. The Company's opening brief was filed in July 2025. Oral argument before a three-judge panel of the Ninth Circuit was held on February 10, 2026.

Initiative Measure No. 2066, which was approved by voters, does not allow the Washington State Energy Code to "in any way prohibit, penalize, or discourage the use of gas for any form of heating, or for uses related to any appliance or equipment, in any building." In May 2025, the King County Superior Court filed an order ruling Initiative Measure No. 2066 unconstitutional. Following the ruling, the Building Industry Association of Washington filed a notice of appeal with the King County Superior Court. The King County Superior Court’s order invalidating Initiative Measure No. 2066 is now pending review by the Washington State Supreme Court. The Court heard oral arguments in the case in January 2026.

48 MDU Resources Group, Inc. Form 10-K

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•In March 2024, the SEC issued Final Rule 33-11275 - The Enhancement and Standardization of Climate-Related Disclosures for Investors. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. In March 2025, the SEC withdrew its defense of the rules. In July 2025, the SEC asked the Eighth Circuit to issue a ruling on the abandoned climate regulations. In September 2025, the Eighth Circuit stated it was pausing its consideration of legal challenges against this rule, pending further action by the SEC.

MDU Resources Group, Inc. Form 10-K 49

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Pipeline

Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in Item 1 - Business. The segment focuses on utilizing its extensive expertise in the design, construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of existing operations, organic growth and investments in energy-related assets within or in close proximity to its current operating areas. The segment focuses on the continual safety and reliability of its systems, which entails building, operating and maintaining safe natural gas pipelines and facilities. The segment continues to evaluate growth opportunities including the expansion of natural gas facilities; incremental pipeline projects; and expansion of energy-related services leveraging on its core competencies. In support of this strategy, the Company completed the following growth projects in 2024 and 2025:

•In March 2024, the 2023 Line Section 27 Expansion project was placed in service and increased system capacity by 175 MMcf of natural gas per day.

•In July 2024, the Line Section 28 Expansion project was placed in service and increased system capacity by 137 MMcf of natural gas per day.

•In November 2024, the Company closed on the purchase of a 28-mile natural gas pipeline lateral in northwestern North Dakota.

•In December 2024, the Wahpeton Expansion project was placed in service and increased system capacity by approximately 20 MMcf of natural gas per day.

•In November 2025, the Minot Expansion Project was placed in service and increased system capacity by 7 MMcf of natural gas per day.

The segment is exposed to natural gas and oil price volatility including fluctuations in basis differentials. Legislative and regulatory initiatives on increased pipeline safety regulations and environmental matters such as the reduction of methane emissions could also impact the price and demand for natural gas.

The pipeline segment is subject to extensive regulation related to certain operational and environmental compliance, cybersecurity, permit terms and system integrity. The Company continues to actively evaluate cybersecurity processes and procedures, including changes in the industry's cybersecurity regulations, for opportunities to further strengthen its cybersecurity protections. Implementation of enhancements and additional requirements is ongoing. The segment reviews and secures existing permits and easements, as well as new permits and easements as necessary, to meet current demand and future growth opportunities on an ongoing basis.

Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. The Company continues to monitor the impact tariffs will have on its costs. The Company continues to actively manage the national supply chain challenges by working with its manufacturers and suppliers to help mitigate some of these risks on its business. The segment regularly experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work which could delay maintenance work and construction projects potentially causing lost revenues and/or increased costs. The Company is partially mitigating these challenges by planning for extended lead times further in advance. The Company expects these delays to continue. Inflationary pressures have moderated, but costs for raw material and contract services remain high. For additional discussion regarding risks and uncertainties, see Item 1A - Risk Factors.

The segment focuses on the recruitment and retention of a skilled workforce to remain competitive and provide services to its customers. The industry in which it operates relies on a skilled workforce to construct energy infrastructure and operate existing infrastructure in a safe manner. A shortage of skilled personnel can create a competitive labor market which could increase costs incurred by the segment. Competition from other pipeline companies can also have a negative impact on the segment.

50 MDU Resources Group, Inc. Form 10-K

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Earnings overview - The following information summarizes the performance of the pipeline segment.

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Operating revenues			$	229.2		$	211.8		$	177.6					8.2		%	19.3		%
Operating expenses:
Operation and maintenance			81.8			75.7			70.8						8.1		%	6.9		%
Depreciation and amortization			32.1			29.4			26.8						9.2		%	9.7		%
Taxes, other than income			14.2			12.2			10.8						16.4		%	13.0		%
Total operating expenses			128.1			117.3			108.4						9.2		%	8.2		%
Operating income			101.1			94.5			69.2						7.0		%	36.6		%
Other income			3.7			6.5			3.9						(43.1)		%	66.7		%
Interest expense			16.7			15.5			13.3						7.7		%	16.5		%
Income before income taxes			88.1			85.5			59.8						3.0		%	43.0		%
Income tax expense			19.9			17.5			12.4						13.7		%	41.1		%
Income from continuing operations			68.2			68.0			47.4						.3		%	43.5		%
Discontinued operations, net of tax*			—			—			(.5)						—		%	(100.0)		%
Net income			$	68.2		$	68.0		$	46.9					.3		%	45.0		%
*Discontinued operations includes interest on debt facilities repaid in connection with the Knife River separation.

Operating statistics
			2025			2024			2023
Transportation volumes (MMdk)			603.3			613.2			567.2
Customer natural gas storage balance (MMdk):
Beginning of period			44.1			37.7			21.2
Net injection (withdrawal)			(6.5)			6.4			16.5
End of period			37.6			44.1			37.7

2025 compared to 2024 Pipeline earnings increased $200,000 as a result of:

•Revenues increased $17.4 million.

◦Increased demand revenue, largely due to:

▪Growth projects placed in service throughout 2024 and in late 2025 of $11.1 million.

▪Increased usage of short-term firm natural gas transportation contracts of $5.7 million.

▪Partially offset by the expiration of certain contracts.

◦Higher interruptible transportation revenue of $1.3 million.

◦Higher non-regulated project revenue of $800,000.

•Operation and maintenance increased $6.1 million.

◦Primarily due to:

▪Higher payroll-related costs of $2.3 million.

▪Higher non-regulated project costs, associated with increased non-regulated project revenue as previously discussed.

▪Also reflected are higher costs associated with services provided to Everus as part of transition services agreement, offset in other income, as described below. The transition services are expected to be complete as of March 2026.

▪Higher contract services of $600,000, auto of $500,000 and insurance costs of $400,000.

•Depreciation and amortization increased $2.7 million due to higher property, plant and equipment balances associated with growth projects placed in-service, as previously discussed, partially offset by fully depreciated assets.

•Taxes, other than income increased $2.0 million, largely resulting from higher property taxes in Montana.

•Other income decreased $2.8 million.

◦Primarily due to:

▪The absence of proceeds received in 2024 from a customer settlement of $2.0 million.

▪Lower AFUDC for the construction of the company's growth projects.

MDU Resources Group, Inc. Form 10-K 51

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◦Partially offset by higher transition services agreement income, as described above.

•Interest expense increased $1.2 million, resulting from higher debt balances to fund capital expenditures, as previously discussed, and lower AFUDC, as previously discussed.

•Income tax expense increased $2.4 million, largely due to the absence of a benefit from an adjustment related to the Company's effective state income tax rate change.

Outlook The Company has continued to experience the effect of associated natural gas production in the Bakken, which has provided opportunities for organic growth projects and increased transportation demand. The completion of organic growth projects has contributed to higher volumes of natural gas the Company transports through its system. Bakken natural gas production is currently at or near record levels and the outlook remains positive with continued growth expected due to increasing gas to oil ratios which may moderate recent decreases in drilling activity.

Increases in national and global natural gas supply have moderated pressure on natural gas prices and price volatility. While the Company believes there will continue to be varying pressures on natural gas production levels and prices, the long-term outlook for natural gas prices continues to provide growth opportunity for industrial supply and demand related projects and seasonal pricing differentials provide opportunities for natural gas storage services.

The Company continues to monitor, evaluate and implement additional GHG emissions reduction strategies, including increased monitoring frequency and emission source control technologies to minimize potential risk.

GHG emissions regulations continue to evolve due to congressional actions and agency reconsideration. Methane Waste Emissions Charge regulations finalized in 2024 were eliminated by a resolution of disapproval passed by Congress and signed by the President in March 2025. The OBBBA postponed the Waste Emissions Charge provisions in the Clean Air Act to 2034. The EPA has issued several actions since the EPA Administrator's announcement regarding 31 historic actions to advance the President's "Power the Great American Comeback", which include extending deadlines for certain oil and gas new source performance standards and a proposal to reconsider the Greenhouse Gas Reporting Program. The Company continues to comply with rules as they remain in effect, and to monitor and assess these rulemaking changes and the potential impacts they may have on its business processes, current and future projects, results of operations and disclosures.

The Company continues to focus on improving existing operations and growth opportunities through organic projects in all areas in which it operates, which includes additional projects supporting the needs of local distribution companies, Bakken area producers, electric generation customers and industrial customers in various stages of development, including:

•Line Section 32 Expansion Project which will provide natural gas transportation service to a new electric generation facility in northwest North Dakota. The project consists of approximately 20 miles of pipe and ancillary facilities and is designed to increase natural gas transportation capacity by 190 MMcf per day, which is supported by a long-term customer agreement. The Company continues to make progress on required surveys and anticipates filing its FERC application in March 2026. The project is dependent on regulatory approvals and is targeted to be in service in late 2028.

•Potential Bakken East Pipeline Project, which could consist of 350 miles of pipeline construction from western North Dakota to the eastern part of the state, plus additional pipeline laterals. The Company continues actively marketing the project and began a binding open season on February 2, 2026, which will conclude on March 13, 2026. The results of the open season will be evaluated to determine the final design, timeline and project cost. In 2025, the Company began working with landowners to conduct environmental and civil surveys along the potential route and plans to continue survey work in the spring of 2026 when weather conditions allow. In August 2025, the North Dakota Industrial Commission selected the project for firm capacity commitments of up to $50 million annually for 10 years.

•Potential Minot Industrial Pipeline Project, which could consist of an approximately 90-mile pipeline from Tioga, North Dakota to Minot, North Dakota and ancillary facilities. The Company has signed an agreement to support the early stage development of the project through the second quarter of 2026. The project would provide incremental natural gas transportation capacity for anticipated industrial demand.

See Capital Expenditures within this section for information on the expenditures related to these growth projects.

52 MDU Resources Group, Inc. Form 10-K

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Other

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Operating revenues			$	.7		$	.2		$	.2					250.0		%	—		%
Operating expenses:
Operation and maintenance			.5			13.3			24.9						(96.2)		%	(46.6)		%
Depreciation and amortization			—			2.2			4.1						(100.0)		%	(46.3)		%
Taxes, other than income			—			.4			.4						(100.0)		%	—		%
Total operating expenses			.5			15.9			29.4						(96.9)		%	(45.9)		%
Operating income (loss)			.2			(15.7)			(29.2)						101.3		%	(46.2)		%
Gain on tax-free exchange of retained shares in Knife River			—			—			186.6						—		%	(100.0)		%
Other income			6.6			16.6			16.4						(60.2)		%	1.2		%
Interest expense			4.9			15.0			19.3						(67.3)		%	(22.3)		%
Income (loss) before income taxes			1.9			(14.1)			154.5						113.5		%	(109.1)		%
Income tax benefit			(.3)			(5.5)			(8.1)						(94.5)		%	(32.1)		%
Income (loss) from continuing operations			2.2			(8.6)			162.6						125.6		%	(105.3)		%
Discontinued operations, net of tax			(1.0)			100.0			85.1						(101.0)		%	17.5		%
Net income			$	1.2		$	91.4		$	247.7					(98.7)		%	(63.1)		%

The Company completed the separations of Knife River, its former construction materials and contracting segment, on May 31, 2023 and Everus, its former construction services segment, on October 31, 2024, into new independent publicly-traded companies. As a result of these separations, the historical results of operations for Knife River and Everus are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the Company, which did not meet the criteria for discontinued operations and are reflected in Other. Also included in discontinued operations are certain strategic initiative costs associated with the separations of Knife River and Everus. Other includes activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023, as well as corporate overhead costs paid by Everus and Knife River for those respective periods which were allocated to the Company's remaining segments in 2025.

Also included in Other is insurance activity at the Company's captive insurer and general and administrative costs and interest expense previously allocated to the exploration and production and refining businesses that did not meet the criteria for discontinued operations.

For the full year, Other reported net income of $1.2 million compared to net income of $91.4 million for 2024. The decrease was primarily due to the absence of the income from discontinued operations in 2025. Partially offsetting the decrease was lower operation and maintenance expense, largely a result of corporate overhead costs classified as continuing operations allocated to the construction services business in 2024, which were allocated to the Company's remaining segments in 2025.

Intersegment Transactions

Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of intersegment transactions. The amounts related to these items were as follows:

Years ended December 31,			2025			2024			2023
			(In millions)
Intersegment transactions:
Operating revenues			$	76.6		$	69.6		$	63.1
Operation and maintenance			$	1.8		$	0.7		$	1.0
Purchased natural gas sold			$	74.8		$	68.9		$	62.1
Other income			$	5.2		$	15.4		$	13.6
Interest expense			$	5.2		$	15.4		$	13.6

For more information on intersegment eliminations, see Item 8 - Note 14.

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Liquidity and Capital Commitments

At December 31, 2025, the Company had cash, cash equivalents and restricted cash of $28.2 million and available borrowing capacity of $418.1 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year and its other operating and capital requirements from various sources, including internally generated funds; credit facilities and commercial paper of the Company and its subsidiaries, as described in Capital resources; and issuance of debt securities and equity securities using the Company's FSA and ATM program as needed.

Cash flows

Years ended December 31,			2025			2024			2023
			(In millions)
Net cash provided by (used in)
Operating activities			$	473.4		$	502.3		$	332.6
Investing activities			(780.9)			(552.7)			(540.7)
Financing activities			268.8			40.3			204.6
Decrease in cash, cash equivalents and restricted cash			(38.7)			(10.1)			(3.5)
Cash, cash equivalents and restricted cash -- beginning of year			66.9			77.0			80.5
Cash, cash equivalents and restricted cash -- end of year			$	28.2		$	66.9		$	77.0

Operating activities

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Income from continuing operations			$	191.4		$	181.1		$	330.1					$	10.3		$	(149.0)
Adjustments to reconcile net income to net cash provided by operating activities			204.9			190.2			3.3						14.7			186.9
Changes in current assets and current liabilities, net of acquisitions:
Receivables			8.4			(30.3)			79.1						38.7			(109.4)
Inventories			4.3			.2			(21.7)						4.1			21.9
Other current assets			54.5			81.0			(48.5)						(26.5)			129.5
Accounts payable			(9.6)			(.4)			(87.2)						(9.2)			86.8
Other current liabilities			24.4			(5.3)			73.4						29.7			(78.7)
Pension and postretirement benefit plan contributions			(3.1)			(3.0)			(7.6)						(.1)			4.6
Other noncurrent changes			(1.1)			(1.7)			(15.6)						.6			13.9
Net cash provided by continuing operations			474.1			411.8			305.3						62.3			106.5
Net cash (used in) provided by discontinued operations			(.7)			90.5			27.3						(91.2)			63.2
Net cash provided by operating activities			$	473.4		$	502.3		$	332.6					$	(28.9)		$	169.7

The changes in cash flows from operating activities generally follow the results of operations as discussed in Business Segment Financial and Operating Data and are affected by changes in working capital.

The decrease in cash flows provided by operating activities in 2025 from 2024 was largely driven by the absence of cash provided by discontinued operations in 2024, as well as the absence of certain fuel cost recoveries in 2025 and increases in certain regulatory cost deferrals. Partially offsetting the decrease was higher collection of accounts receivable associated with higher gas costs in December 2024, lower cash used for payment of other current liabilities, including compliance costs, accrued compensation, data center customer deposits, and net environmental compliance costs, all at the natural gas distribution business.

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Investing activities

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Capital expenditures			$	(770.4)		$	(522.8)		$	(484.1)					$	(247.6)		$	(38.7)
Net proceeds from sale or disposition of property			—			0.7			0.2						(.7)			.5
Cost of removal, net of salvage value			(11.3)			(5.5)			1.2						(5.8)			(6.7)
Investments			(4.2)			(5.2)			(2.4)						1.0			(2.8)
Proceeds from investment excess cash and cost basis withdrawal			5.0			9.0			20.0						(4.0)			(11.0)
Net cash used in continuing operations			(780.9)			(523.8)			(465.1)						(257.1)			(58.7)
Net cash used in discontinued operations			—			(28.9)			(75.6)						28.9			46.7
Net cash used in investing activities			$	(780.9)		$	(552.7)		$	(540.7)					$	(228.2)		$	(12.0)

The increase in cash used in investing activities in 2025 from 2024 was primarily due to higher capital expenditures at the electric business, largely related to the Badger Wind Farm, partially offset by lower capital expenditures at the pipeline business due to the absence of the 2024 Wahpeton Expansion project. Partially offsetting this was the absence of cash used in discontinued operations with the spinoff of Everus.

Financing activities 

															2025 vs. 2024			2024 vs. 2023
Years ended December 31,			2025			2024			2023						Variance			Variance
			(In millions)
Issuance of short-term borrowings			$	—		$	—		$	810.0					$	—		$	(810.0)
Repayment of short-term borrowings			—			(95.0)			(433.9)						95.0			338.9
Issuance of long-term debt			565.4			308.6			594.7						256.8			(286.1)
Repayment of long-term debt			(179.5)			(182.1)			(568.9)						2.6			386.8
Debt issuance costs			(4.3)			(2.5)			(2.5)						(1.8)			—
Costs of issuance of common stock			(.1)			(.1)			—						—			(.1)
Dividends paid			(108.2)			(102.9)			(161.3)						(5.3)			58.4
Repurchase of common stock			—			—			(4.8)						—			4.8
Tax withholding on stock-based compensation			(4.5)			(2.6)			(3.1)						(1.9)			.5
Net cash provided by (used in) continuing operations			268.8			(76.6)			230.2						345.4			(306.8)
Net cash provided by (used in) discontinued operations			—			116.9			(25.6)						(116.9)			142.5
Net cash provided by financing activities			$	268.8		$	40.3		$	204.6					$	228.5		$	(164.3)

The increase in cash provided by financing activities in 2025 from 2024 was primarily due higher long-term debt issuance proceeds used to finance capital expenditure projects, primarily at the electric business. Also contributing was the absence of 2024 short-term borrowing repayment at the natural gas distribution business. Partially offsetting these items was the absence of cash provided by discontinued operations in 2024.

Defined benefit pension plans

The Company has noncontributory qualified defined benefit pension plans for certain employees. Plan assets consist of investments in equity and fixed-income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the pension plans. Actuarial assumptions include assumptions about the discount rate and expected return on plan assets. For 2025, the Company assumed a long-term rate of return on its qualified defined pension plan assets of 6.5 percent. Differences between actuarial assumptions and actual plan results are deferred and amortized into expense when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. Therefore, this change in asset values will be reflected in future expenses of the plans beginning in 2026. The funded status of the plans improved $6.3 million from prior year, primarily due to increase in plan assets, as discussed previously.

At December 31, 2025, the pension plans' projected benefit obligations exceeded these plans' assets by approximately $18.5 million. Pretax pension expense reflected in the Consolidated Statements of Income for the years ended

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December 31, 2025 and 2024, was $3.4 million and $835,000, respectively. Pretax pension income reflected in the Consolidated Statements of Income for the year ended December 31, 2023 was $580,000. The Company's pension expense is currently projected to be approximately $4.7 million in 2026. Funding for the pension plans is actuarially determined. The Company expects to contribute the minimum funding requirement of $3.8 million in 2026. For the years ended December 31, 2025 and 2024, the Company contributed the minimum funding requirement of $3.4 million and $2.9 million, respectively. There were no minimum required contributions for the year ended December 31, 2023, due to an additional contribution of $20.0 million in 2019, which created prefunding credits that were used in future periods. For more information on the Company's pension plans, see Item 8 - Note 15.

Capital expenditures

The Company's capital expenditures, excluding discontinued operations, for 2023 through 2025 and as anticipated for 2026 through 2028 are summarized in the following table.

			Actual (b)												Estimated
			2023			2024			2025			(c)			2026			2027			2028
			(In millions)
Capital expenditures:
Electric			$	110		$	116		$	430		(d)			$	158		$	309		$	250
Natural gas distribution			275			285			301						342			295			240
Pipeline			116			127			61						60			70			181
Total capital expenditures (a)(e)			$	501		$	528		$	792					$	560		$	674		$	671

(a)Capital expenditures for 2023 are reported as gross capital expenditures. Capital expenditures for 2024 and 2025 as well as estimated expenditures for 2026 through 2028 are reported on a net basis.

(b)Capital expenditures for 2023, 2024 and 2025 include noncash transactions such as capital expenditure-related accounts payable and AFUDC totaling $(13.6) million, $7.1 million, and $(10.8) million, respectively.

(c)2025 capital expenditures were funded by cash provided from operating activities, long-term debt issuances and borrowings under credit facilities and issuance of commercial paper of the Company and its subsidiaries.

(d)The Company completed the final $264.6 million payment for a 49 percent ownership interest in Badger Wind Farm, which was acquired and placed in service on December 31, 2025. This amount was previously included in 2026 estimates.

(e)Excludes Other category.

Planned utility investments in the Company's estimated capital expenditures for 2026 through 2028 include system upgrades, substation improvements and generation projects, construction of JETx, system replacements, expansion and modernization projects to meet demand from a growing customer base, including new service extensions and capacity expansion to accommodate economic and population growth across the Company's eight-state territory. The pipeline business will continue to evaluate customer-driven projects, including expansion projects, to serve power generation and industrial demand in the region. In addition, the pipeline will focus on system maintenance and expanding capacity where market conditions support additional investment. A number of projects are included in the planned investments as the Company continues to invest in safe, reliable and environmentally-responsible energy delivery infrastructure across its regulated businesses. For more information on the Company's growth projects, see Business Segment Financial and Operating Data.

The Company continues to evaluate potential future acquisitions and other growth opportunities that would be incremental to the outlined capital program; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates in the preceding table. The Company continuously monitors its capital expenditures for project delays and changes in economic viability and adjusts as necessary. It is anticipated that all of the funds required for capital expenditures for the years 2026 through 2028 will be funded by various sources, including equity issuance, debt financing and internally generated funds.

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Capital resources

The Company requires significant cash to support and grow its businesses. The primary sources of cash other than cash generated from operating activities are cash from revolving credit facilities, the issuance of long-term debt and the sale of equity securities.

Debt resources Certain debt instruments of the Company and its subsidiaries contain restrictive and financial covenants and cross-default provisions. In order to borrow under the respective debt agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions. Intermountain was not in compliance with its minimum interest coverage ratio for the period ended September 30, 2025, which constituted an event of default under the terms of the Intermountain NPAs. In addition, the event of default under the terms of the Intermountain NPAs constituted a cross-default under the terms of certain NPAs of MDU Energy Capital and revolving credit agreements held by the Company and Intermountain. Subsequent to September 30, 2025, Intermountain and MDU Energy Capital obtained waivers for this non-compliance from the holders of a majority of their respective outstanding notes, and Intermountain and the Company obtained waivers from the lenders of the revolving credit agreements, which collectively cured the impact of any events of default. The Company and its subsidiaries were in compliance with applicable covenants at December 31, 2025. In the event the Company or its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. As of December 31, 2025, the Company had investment grade credit ratings at all entities issuing debt which carried public ratings. For more information on the covenants, certain other conditions and cross-default provisions, outstanding revolving credit facilities, and new long-term debt issuances, see Item 8 - Note 9.

Equity offerings In August 2025, the Company entered into an EDA pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $400.0 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs. Since the establishment of the ATM offering program, the Company did not issue common stock pursuant to the EDA nor enter into any FSAs related to the EDA.

On December 5, 2025, the Company completed a follow-on public offering of 10,152,284 of shares of the Company's common stock at a public offering price of $19.70 per share. In addition, on December 23, 2025, the underwriters exercised their option to purchase 1,522,842 additional shares of the Company's common stock. Pursuant to the FSAs entered into in connection with the offering, the Company has discretion to settle the FSAs on one or more settlement dates prior to December 6, 2027, subject to certain price adjustments as set forth in the FSAs as well as adjustments for transaction and other associated fees. The FSAs will be physically settled with shares of common stock issued by the Company, unless the Company elects to settle the FSAs in net cash or net shares, subject to certain conditions. If the Company elects to physically settle the FSAs, the Company will physically issue shares of common stock to the banking counterparties at the then-applicable forward sale price and receive proceeds at that time.

Actual cash proceeds, if any, for settlement of FSAs will depend on the method and timing the Company elects for settlement. Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in the Company's diluted earnings per share calculation using the treasury stock method. For more detailed information about the Company's equity transactions, see Item 8 - Note 11.

Dividend restrictions

For information on the Company's dividends and dividend restrictions, see Item 8 - Note 11.

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Material cash requirements

For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Item 8 - Notes 9 and 17. At December 31, 2025, the Company's material cash requirements under these obligations were as follows:

			Less than 1 year			1-3 years			3-5 years			More than 5 years			Total
			(In millions)
Long-term debt maturities*			$	144.7		$	354.4		$	550.1		$	1,635.7		$	2,684.9
Estimated interest payments**			128.2			214.9			199.9			985.2			1,528.2
Operating leases			4.1			5.9			5.2			45.9			61.1
Purchase commitments			610.5			415.1			232.2			542.1			1,799.9
			$	887.5		$	990.3		$	987.4		$	3,208.9		$	6,074.1

*    Unamortized debt issuance costs and discount are excluded from the table.

**    Represents the estimated interest payments associated with the Company's long-term debt outstanding at December 31, 2025, assuming current interest rates and consistent amounts outstanding until their respective maturity dates over the periods indicated in the table above.

Material short-term cash requirements of the Company include repayment of outstanding borrowings and interest payments on those agreements, payments on operating lease agreements, payment of obligations on purchase commitments and asset retirement obligations. At December 31, 2025, the current portion of asset retirement obligations was $329,000 and was included in Other accrued liabilities on the Consolidated Balance Sheets.

Material long-term cash requirements of the Company include repayment of outstanding borrowings and interest payments on those agreements, payments on operating lease agreements, payment of obligations on purchase commitments and asset retirement obligations. At December 31, 2025, the Company had total liabilities of $431.9 million related to asset retirement obligations that are excluded from the table above. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. For more information, see Item 8 - Note 10.

Not reflected in the previous table are $1.5 million in uncertain tax positions at December 31, 2025.

The Company's minimum funding requirements for its defined benefit pension plans for 2026, which are not reflected in the previous table, is $3.8 million. For information on potential contributions above the funding minimum requirements, see item 8 - Note 15.

The Company's MEPP contributions are based on union employee payroll, which cannot be determined in advance for future periods. The Company may also be required to make additional contributions to its MEPP as a result of its funded status. For more information, see Item 1A - Risk Factors and Item 8 - Note 15.

New Accounting Standards

For information regarding new accounting standards, see Item 8 - Note 2, which is incorporated herein by reference.

Critical Accounting Estimates

The Company has prepared its financial statements in conformity with GAAP. The preparation of its financial statements requires management 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 financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Management reviews these estimates and assumptions based on historical experience, changes in business conditions and other relevant factors believed to be reasonable under the circumstances.

Critical accounting estimates are defined as estimates that require management to make assumptions about matters that are uncertain at the time the estimate was made and changes in the estimates could have a material impact on the Company's financial position or results of operations. The Company's critical accounting estimates are subject to judgments and uncertainties that affect the application of its significant accounting policies discussed in Item 8 - Note 2. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised.

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Consequently, the Company's financial position or results of operations may be materially different when reported under different conditions or when using different assumptions in the application of the following critical accounting estimates.

Goodwill

The Company performs its goodwill impairment testing annually in the fourth quarter. In addition, the test is performed on an interim basis whenever events or circumstances indicate that the carrying amount of goodwill may not be recoverable. Examples of such events or circumstances may include a significant adverse change in business climate, weakness in an industry in which the Company's reporting units operate or recent significant cash or operating losses with expectations that those losses will continue.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. As of December 31, 2025, the only operating segment with goodwill was the natural gas distribution segment. For more information on the Company's operating segments, see Item 8 - Note 14.

Goodwill impairment, if any, is measured by comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the goodwill of the reporting unit is not impaired. If the carrying value of a reporting unit exceeds its fair value, the Company must record an impairment loss for the amount that the carrying value of the reporting unit, including goodwill, exceeds the fair value of the reporting unit. For the years ended December 31, 2025, 2024, and 2023, there were no impairment losses recorded.

At October 31, 2025, the Company's annual impairment testing indicated there was no impairment at its natural gas distribution reporting unit. The estimated fair value of the natural gas distribution reporting unit substantially exceeded its carrying value ("cushion"), which includes $345.7 million of goodwill, by approximately 41 percent. The increase in the natural gas distribution reporting unit's cushion from the prior year was primarily driven by improved valuation results under the market approach, reflecting higher industry multiples, as well as an increase in the income approach valuation due to additional rate relief in 2025 compared to 2024.

Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, long-term growth rates, amount and timing of estimated capital expenditures, inflation rates, risk adjusted cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information.

The Company uses a discounted cash flow methodology for its income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the risk adjusted cost of capital at each reporting unit. The risk adjusted cost of capital was 5.8 percent, 5.9 percent and 6.7 percent for 2025, 2024, and 2023, respectively.

Under the market approach, the Company estimates fair value using various multiples derived from enterprise value to EBITDA for comparative peer companies. These multiples are applied to operating data to arrive at an indication of fair value. In addition, the Company also uses a rate base multiple, based on recent comparable industry transactions. With the exception of the rate base trading multiple, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company used a 20 percent control premium in 2025, 2024, and 2023.

The Company uses significant judgment in estimating its five-year forecast. The assumptions underlying cash flow projections are in sync as applicable with the Company's strategy and assumptions. Future projections are heavily correlated with the current year results of operations. Future results of operations may vary due to economic and financial impacts. The long-term growth rates are developed by management based on industry data, management's knowledge of the industry and management's strategic plans, which was 3.0 percent in 2025, 2024, and 2023.

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Regulatory accounting

The Company is subject to rate regulation by state public service commissions and/or the FERC. Regulatory assets generally represent incurred or accrued costs that have been deferred and are expected to be recovered in rates charged to customers. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

Management continually assesses the likelihood of recovery in future rates of incurred costs and refunds to customers associated with regulatory assets and liabilities. Decisions made by the various regulatory agencies can directly impact the amount and timing of these items. Therefore, expected recovery or refund of these deferred items generally is based on specific ratemaking decisions or precedent for each item. If future recovery of costs is no longer probable, the Company would be required to include those costs in the statement of income or accumulated other comprehensive loss in the period in which it is no longer deemed probable. The Company believes that the accounting subject to rate regulation remains appropriate and its regulatory assets are probable of recovery in current rates or in future rate proceedings. At December 31, 2025 and 2024, the Company's regulatory assets were $476.8 million and $537.8 million, respectively, and regulatory liabilities were $620.9 million and $596.3 million, respectively. At December 31, 2025 and 2024, regulatory assets in recovery were $437.6 million and $478.5 million, respectively, and regulatory assets not in recovery were $39.2 million and $59.3 million, respectively.

Pension and other postretirement benefits

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions.

The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term return on plan assets, actuarially determined mortality data and health care cost trend rates. In selecting the expected long-term return on plan assets, which is considered to be one of the key variables in determining benefit expense or income, the Company considers historical returns, current market conditions, the mix of investments and expected future market trends, including changes in interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate. In selecting the discount rate, the Company matches forecasted future cash flows of the pension and postretirement plans to a yield curve which consists of a hypothetical portfolio of high-quality corporate bonds with varying maturity dates, as well as other factors, as a basis. The Company's pension and other postretirement benefit plan assets are primarily made up of equity and fixed-income investments. Fluctuations in actual equity and bond market returns, as well as changes in general interest rates, may result in increased or decreased pension and other postretirement benefit costs in the future. Health care cost trend rates are determined by historical and future trends.

The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is known when the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets and health care cost trend rates. A 50 basis point change in the assumed discount rate and the expected long-term return on plan assets would have had the following effects at December 31, 2025:

			Pension Benefits						Other Postretirement Benefits
			50 Basis Point Increase			50 Basis Point Decrease			50 Basis Point Increase			50 Basis Point Decrease
Discount rate			(In millions)
Projected benefit obligation as of December 31, 2025			$	(10.2)		$	11.0		$	(1.5)		$	1.6
Net periodic benefit cost (credit) for 2026			$	.1		$	(.1)		$	—		$	—
Expected long-term return on plan assets
Net periodic benefit cost (credit) for 2026			$	(1.2)		$	1.2		$	(.4)		$	.4

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A 100 basis point change in the assumed health care cost trend rates would have had the following effects at December 31, 2025:

			100 Basis  Point Increase			100 Basis  Point Decrease
			(In millions)
Service and interest cost components for 2026			$	—		$	—
Postretirement benefit obligation as of December 31, 2025			$	0.3		$	(0.3)

The Company plans to continue to use its current methodologies to determine plan costs. For more information on the assumptions used in determining plan costs, see Item 8 - Note 15.

Income taxes

The Company is required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to estimate the Company's obligation to taxing authorities. These tax obligations include income, property, franchise and sales/use taxes. Judgments related to income taxes require the recognition in the Company's financial statements that a tax position is more-likely-than-not to be sustained on audit.

Judgment and estimation is required in developing the provision for income taxes and the reporting of tax-related assets and liabilities and, if necessary, any valuation allowances. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income tax could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows and tax-related assets and liabilities. In addition, the effective tax rate may be affected by other changes including the allocation of property, payroll and revenues between states.

The Company assesses the deferred tax assets for recoverability taking into consideration historical and anticipated earnings levels; the reversal of other existing temporary differences; available net operating losses and tax carryforwards; and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, a valuation allowance against the deferred tax assets. As facts and circumstances change, adjustment to the valuation allowance may be required.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest rate risk

The Company uses fixed and variable rate long-term debt to partially finance operations and capital expenditures which exposes the Company to market risk related to changes in interest rates. Higher interest rates have resulted in and will likely continue to result in higher borrowing costs on new debt and existing variable interest rate debt.

As of December 31, 2025, approximately 12.2 percent of the outstanding debt recorded on the balance sheet consisted of variable interest rate facilities (which uses SOFR as the benchmark rate). Based on balances outstanding for these borrowings as of December 31, 2025, an increase of 1 percent in the interest rate on the Company's outstanding variable interest rate facilities would result in an estimated $3.3 million pre-tax annual increase in interest expense over the next twelve months. For additional information on the Company's long-term debt, see Item 8 - Notes 8 and 9. At December 31, 2025 and 2024, the Company had no outstanding interest rate hedges.

The following table shows the amount of long-term debt, which excludes unamortized debt issuance costs and discount, and related weighted average interest rates, both by expected maturity dates, as of December 31, 2025.

			2026			2027			2028			2029			2030			Thereafter			Total			Fair Value
			(Dollars in millions)
Long-term debt:
Fixed rate			$	144.7		$	274.7		$	79.7		$	74.7		$	146.7		$	1,635.7		$	2,356.2		$	2,064.5
Weighted average interest rate			5.7		%	4.9		%	4.4		%	4.5		%	4.9		%	4.7		%	4.8		%
Variable rate			$	—		$	—		$	—		$	—		$	328.7		$	—		$	328.7		$	328.7
Weighted average interest rate			—		%	—		%	—		%	—		%	4.7		%	—		%	4.7		%

Commodity price risk

The Company enters into commodity price derivative contracts to minimize the price volatility associated with natural gas costs for its customers at its natural gas distribution segment. At December 31, 2025 and 2024, these contracts were not material. For more information on the Company's derivatives, see Item 8 - Note 2.

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Item 8. Financial Statements and Supplementary Data

Management's Report on Internal Control Over Financial Reporting

The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. 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.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013).

Based on our evaluation under the framework in Internal Control-Integrated Framework (2013), management concluded that the Company's internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2025, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.

/s/ Nicole A. Kivisto			/s/ Jason L. Vollmer
Nicole A. Kivisto			Jason L. Vollmer
President and Chief Executive Officer			Chief Financial Officer

MDU Resources Group, Inc. Form 10-K 63

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of MDU Resources Group, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. and subsidiaries (the “Company”) as of December 31, 2025 and December 31, 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and the schedules 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 December 31, 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 20, 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 and 6 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by federal and state utility regulatory agencies (collectively, the “Commissions”), which have jurisdiction with respect to the rates of electric, natural gas distribution and pipeline companies. The Company’s regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery, refund or future rate reduction of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income taxes.

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Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on the Company’s investment in the regulated businesses. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations.

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 impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) refunds or future rate reduction to customers. Given 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 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 property, plant, and equipment and deferred as regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and 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.

•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 for the Company and other public utilities in the Company’s significant jurisdictions, 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 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, and for any evidence that might contradict management’s assertions.

•We obtained an analysis from management 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.

•We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new regulatory assets or liabilities.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 20, 2026

We have served as the Company's auditor since 2002.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of MDU Resources Group, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of MDU Resources 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 20, 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 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 20, 2026

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Consolidated Statements of Income

Years ended December 31,			2025			2024			2023
			(In thousands, except per share amounts)
Operating revenues			$	1,875,066		$	1,757,978		$	1,803,352
Operating expenses:
Purchased natural gas sold			671,466			630,403			742,965
Electric fuel and purchased power			158,995			141,148			134,779
Operation and maintenance			433,023			414,491			407,081
Depreciation and amortization			206,708			200,078			190,450
Taxes, other than income			114,497			106,216			103,133
Total operating expenses			1,584,689			1,492,336			1,578,408
Operating income			290,377			265,642			224,944
Realized gain on tax-free exchange of the retained shares in Knife River			—			—			186,556
Other income			28,349			41,367			33,454
Interest expense			107,749			108,347			104,624
Income before income taxes			210,977			198,662			340,330
Income taxes			19,570			17,589			10,213
Income from continuing operations			191,407			181,073			330,117
Discontinued operations, net of tax			(1,012)			100,035			84,590
Net income			$	190,395		$	281,108		$	414,707
Earnings per share - basic:
Income from continuing operations			$	.94		$	.89		$	1.62
Discontinued operations, net of tax			(.01)			.49			.42
Earnings per share - basic			$	.93		$	1.38		$	2.04
Earnings per share - diluted:
Income from continuing operations			$	.93		$	.88		$	1.62
Discontinued operations, net of tax			—			.49			.41
Earnings per share - diluted			$	.93		$	1.37		$	2.03
Weighted average common shares outstanding - basic			204,291			203,867			203,640
Weighted average common shares outstanding - diluted			205,300			204,653			203,938

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Comprehensive Income

Years ended December 31,			2025			2024			2023
			(In thousands)
Net income			$	190,395		$	281,108		$	414,707
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $0, $0 and $15 in 2025, 2024 and 2023, respectively			—			—			81
Postretirement liability adjustment:
Postretirement liability (losses) gains arising during the period, net of tax of $(202), $360 and $(201) in 2025, 2024 and 2023, respectively			(397)			1,049			(646)
Amortization of postretirement liability losses included in net periodic benefit credit, net of tax of $168, $145 and $78 in 2025, 2024 and 2023, respectively			355			432			242
Postretirement liability adjustment			(42)			1,481			(404)
Net unrealized gain on available-for-sale investments:
Net unrealized gain on available-for-sale investments arising during the period, net of tax of $29, $23 and $46 in 2025, 2024 and 2023, respectively			110			85			173
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $4, $5 and $11 in 2025, 2024 and 2023, respectively			15			20			43
Net unrealized gain on available-for-sale investments			125			105			216
Other comprehensive income (loss)			83			1,586			(107)
Comprehensive income attributable to common stockholders			$	190,478		$	282,694		$	414,600

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Balance Sheets

December 31,						2025			2024
Assets						(In thousands, except shares and per share amounts)
Current assets:
Cash, cash equivalents and restricted cash						$	28,212		$	66,904
Receivables, net						258,631			274,303
Current regulatory assets						179,579			215,436
Inventories						39,052			44,940
Current environmental allowances						26,194			23,304
Prepayments and other current assets						40,768			41,372
Total current assets						572,436			666,259
Noncurrent assets:
Property, plant and equipment						8,264,972			7,554,063
Less accumulated depreciation and amortization						2,304,787			2,209,771
Net property, plant and equipment						5,960,185			5,344,292
Goodwill						345,736			345,736
Regulatory assets						297,218			322,350
Investments						121,177			115,459
Environmental allowances						112,376			66,170
Other						213,078			178,552
Total noncurrent assets						7,049,770			6,372,559
Total assets						$	7,622,206		$	7,038,818
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year						$	144,700		$	161,700
Accounts payable						148,970			150,070
Regulatory liabilities due within one year						148,584			137,167
Taxes payable						44,686			43,372
Dividends payable						28,614			26,511
Accrued compensation						34,666			35,264
Current environmental obligations						24,086			19,561
Other accrued liabilities						110,917			104,953
Total current liabilities						685,223			678,598
Noncurrent liabilities:
Long-term debt						2,532,155			2,130,910
Deferred income taxes						437,286			441,320
Regulatory liabilities						472,329			459,170
Asset retirement obligations						431,587			406,351
Environmental obligations						108,448			58,457
Other						182,261			173,438
Total noncurrent liabilities						4,164,066			3,669,646
Stockholders' equity:
Common stock Authorized - 500,000,000 shares, $1.00 par value Shares issued - 204,382,821 at December 31, 2025 and 203,934,578 at December 31, 2024						204,383			203,935
Other paid-in capital						1,476,355			1,473,738
Retained earnings						1,108,894			1,029,699
Accumulated other comprehensive loss						(16,715)			(16,798)
Total stockholders' equity						2,772,917			2,690,574
Total liabilities and stockholders' equity						$	7,622,206		$	7,038,818

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Equity

Years ended December 31, 2025, 2024 and 2023
									Other Paid-in Capital			Retained Earnings			Accumu- lated Other Compre-hensive  Loss
			Common Stock															Treasury Stock
			Shares			Amount												Shares			Amount			Total
			(In thousands, except shares)
At December 31, 2022			204,162,814			$	204,163		$	1,466,037		$	1,951,138		$	(30,583)		(538,921)			$	(3,626)					$	3,587,129
Net income			—			—			—			414,707			—			—			—						414,707
Other comprehensive loss			—			—			—			—			(107)			—			—						(107)
Dividends declared on common stock			—			—			—			(142,033)			—			—			—						(142,033)
Employee stock-based compensation			—			—			6,781			—			—			—			—						6,781
Repurchase of common stock			—			—			—			—			—			(153,622)			(4,811)						(4,811)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings			—			—			(7,851)			—			—			153,622			4,811						(3,040)
Separation of Knife River			(538,921)			(539)			—			(970,119)			12,306			538,921			3,626						(954,726)
Issuance of common stock			65,197			65			1,268			—			—			—			—						1,333
At December 31, 2023			203,689,090			203,689			1,466,235			1,253,693			(18,384)			—			—						2,905,233
Net Income			—			—			—			281,108			—			—			—						281,108
Other comprehensive income			—			—			—			—			1,586			—			—						1,586
Dividends declared on common stock			—			—			—			(104,786)			—			—			—						(104,786)
Employee stock-based compensation			—			—			9,572			—			—			—			—						9,572
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings			199,147			199			(2,822)			—			—			—			—						(2,623)
Separation of Everus			—			—			—			(400,316)			—			—			—						(400,316)
Issuance of common stock			46,341			47			753			—			—			—			—						800
At December 31, 2024			203,934,578			203,935			1,473,738			1,029,699			(16,798)			—			—						2,690,574
Net income			—			—			—			190,395			—			—			—						190,395
Other comprehensive income			—			—			—			—			83			—			—						83
Dividends declared on common stock			—			—			—			(111,200)			—			—			—						(111,200)
Employee stock-based compensation			—			—			6,556			—			—			—			—						6,556
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings			396,592			396			(4,872)			—			—			—			—						(4,476)
Issuance of common stock			51,651			52			933			—			—			—			—						985
At December 31, 2025			204,382,821			$	204,383		$	1,476,355		$	1,108,894		$	(16,715)		—			$	—					$	2,772,917

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Cash Flows

Years ended December 31,			2025			2024			2023
			(In thousands)
Operating activities:
Net income			$	190,395		$	281,108		$	414,707
Less: (loss) income from discontinued operations, net of tax			(1,012)			100,035			84,590
Income from continuing operations			191,407			181,073			330,117
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			206,708			200,078			190,450
Deferred income taxes			(8,923)			(16,078)			(1,309)
Provision for credit losses			6,920			6,558			7,422
Amortization of debt issuance costs			1,259			1,828			1,013
Employee stock-based compensation costs			6,556			8,423			5,505
Pension and postretirement benefit plan net periodic benefit credit			(1,069)			(3,837)			(5,380)
Unrealized (gains) on investments			(6,575)			(5,942)			(7,431)
Losses (gains) on sales of assets			25			(857)			(347)
Gain on tax-free exchange of the retained shares in Knife River			—			—			(186,556)
Changes in current assets and liabilities, net of acquisitions:
Receivables			8,353			(30,310)			79,111
Inventories			4,342			246			(21,729)
Other current assets			54,459			80,977			(48,492)
Accounts payable			(9,618)			(443)			(87,209)
Other current liabilities			24,446			(5,252)			73,365
Pension and postretirement benefit plan contributions			(3,079)			(3,000)			(7,643)
Other noncurrent changes			(1,121)			(1,651)			(15,554)
Net cash provided by continuing operations			474,090			411,813			305,333
Net cash (used in) provided by discontinued operations			(725)			90,505			27,294
Net cash provided by operating activities			473,365			502,318			332,627
Investing activities:
Capital expenditures			(770,394)			(522,824)			(484,136)
Net proceeds from sale or disposition of property			—			691			260
Cost of removal, net of salvage value			(11,283)			(5,539)			1,170
Investments			(4,182)			(5,155)			(2,423)
Proceeds from investment excess cash and cost basis withdrawal			5,000			9,000			20,000
Net cash used in continuing operations			(780,859)			(523,827)			(465,129)
Net cash used in discontinued operations			—			(28,858)			(75,662)
Net cash used in investing activities			(780,859)			(552,685)			(540,791)
Financing activities:
Issuance of short-term borrowings			—			—			810,000
Repayment of short-term borrowings			—			(95,000)			(433,901)
Issuance of long-term debt			565,350			308,600			594,700
Repayment of long-term debt			(179,466)			(182,135)			(568,883)
Debt issuance costs			(4,283)			(2,456)			(2,521)
Costs of issuance of common stock			(79)			(50)			—
Dividends paid			(108,244)			(102,939)			(161,316)
Repurchase of common stock			—			—			(4,811)
Tax withholding on stock-based compensation			(4,476)			(2,623)			(3,040)
Net cash provided by (used in) continuing operations			268,802			(76,603)			230,228
Net cash provided by (used in) discontinued operations			—			116,899			(25,606)
Net cash provided by financing activities			268,802			40,296			204,622
Decrease in cash, cash equivalents and restricted cash			(38,692)			(10,071)			(3,542)
Cash, cash equivalents and restricted cash - beginning of year			66,904			76,975			80,517
Cash, cash equivalents and restricted cash - end of year *			$	28,212		$	66,904		$	76,975

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Supplemental cash flow information:
Cash expenditures during the year for:
Interest, net**			$	99,210		$	108,242		$	112,839
Income taxes paid, net***			$	30,838		$	43,572		$	12,162
Noncash investing and financing transactions:
Property, plant and equipment additions in accounts payable			$	45,338		$	36,820		$	46,364
Right-of-use assets obtained in exchange for new operating lease liabilities			$	14,905		$	1,787		$	2,265
Debt for equity exchange of retained shares in Knife River			$	—		$	—		$	293,239

*    Includes cash of discontinued operations of $16.5 million for the year ended December 31, 2023.

**    AFUDC - borrowed was $7.4 million, $11.0 million and $10.0 million for the years ended December 31, 2025, 2024, and 2023, respectively.

***    Income taxes paid, including discontinued operations, were $30.8 million, $80.9 million and $62.5 million for the years ended December 31, 2025, 2024, and 2023, respectively.

The accompanying notes are an integral part of these consolidated financial statements.

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Notes to Consolidated Financial Statements

Note 1 - Basis of Presentation

The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and other. For further descriptions of the Company's businesses, see Note 14.

On May 31, 2023, the Company completed the separation of Knife River, formerly the construction materials and contracting segment, resulting in Knife River becoming an independent, publicly-traded company. The Company's board of directors approved the distribution of approximately 90 percent of the issued and outstanding shares of Knife River to the Company's stockholders. Stockholders of the Company received one share of Knife River common stock for every four shares of the Company's common stock held on May 22, 2023, the record date for the distribution. The Company retained approximately 10 percent or 5.7 million shares of Knife River common stock immediately following the separation, which were disposed of in a tax-free exchange in November 2023. The separation of Knife River was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

On October 31, 2024, the Company completed the separation of Everus, its construction services business, resulting in Everus becoming an independent, publicly-traded company. The Company's board of directors approved the distribution of all the outstanding shares of Everus common stock to the Company's stockholders. Stockholders of the Company received one share of Everus common stock for every four shares of the Company's common stock held as of the close of business on October 21, 2024, the record date for the distribution. The separation of Everus was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

The Company's consolidated financial statements and accompanying notes for the current and prior periods have been restated to present the results of operations and the assets and liabilities of Knife River and Everus as discontinued operations, other than certain corporate overhead costs of the Company historically allocated to Knife River and Everus, which are reflected in Other. Also included in discontinued operations in the Consolidated Statements of Income are the supporting activities of Fidelity and certain interest expense related to financing activity associated with the Knife River and Everus separations. The assets and liabilities of the Company's discontinued operations are included in current assets of discontinued operations, noncurrent assets of discontinued operations, current liabilities of discontinued operations and noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations. For more information on discontinued operations, see Note 3.

Management has also evaluated the impact of events occurring after December 31, 2025, up to the date of issuance of these consolidated financial statements on February 20, 2026, that would require recognition or disclosure in the financial statements.

Principles of consolidation

The consolidated financial statements were prepared in accordance with GAAP and include the accounts of the Company and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to regulated operations in accordance with GAAP. For more information on intercompany revenues, see Note 14.

The statements also include the Company's ownership interests in the assets, liabilities and expenses of jointly owned electric transmission and generating facilities. See Note 16 for additional information.

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Use of estimates

The preparation of financial statements in conformity with GAAP requires the Company 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 financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as long-lived assets and goodwill; property depreciable lives; tax provisions; revenue recognized using the cost-to-cost measure of progress for contracts; expected credit losses; environmental and other loss contingencies; regulatory assets expected to be recovered in rates charged to customers; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; lease classification; present value of right-of-use assets and lease liabilities; and the valuation of stock-based compensation. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Note 2 - Significant Accounting Policies

New accounting standards

The following table provides a brief description of the accounting pronouncements applicable to the Company and the potential impact on its financial statements and/or disclosures:

Standard			Description			Effective date			Impact on financial statements/disclosures
Recently adopted accounting standards
ASU 2023-09 Income Taxes - Improvements to Income Tax Disclosures an Amendment, December 2023			In December 2023, the FASB issued guidance to address investors requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information and effectiveness of income tax disclosures.			December 31, 2025			The Company has adopted the guidance prospectively and disclosures have been updated to ensure compliance with the new guidance. See Note 13.
ASU 2024-01 Compensation - Stock Compensation			In March 2024, the FASB issued Improvements to GAAP through an example to demonstrate application of the scope of paragraph 718-10-15-3 to determine whether profits interest and similar awards should be accounted in Compensation - Stock Compensation.			December 31, 2025			The Company has evaluated and did not have a material impact from the scope clarification in the new guidance. See Note 12 for additional information on Stock Compensation.
Recently issued accounting standards not yet adopted
ASU 2024-03 Disaggregation of Income Statement Expenses			In November 2024, the FASB issued guidance to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expense captions (such as cost of sales, selling, general, and administrative; and research and development).			Effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027.			The Company is currently evaluating the impact the guidance will have on its disclosures for the year ended December 31, 2027.
ASU 2025-05 Measurement of Credit Losses for Accounts Receivable and Contract Assets			In July 2025, the FASB issued guidance on applying a practical expedient when estimating expected credit losses on current accounts receivable and/or current contract assets arising from transactions under ASC Topic 606 - Revenue from Contracts with Customers.			Effective for annual reporting periods beginning after December 15, 2025.			The Company is currently evaluating the impact the guidance will have on its results of operations, financial position, cash flows, and disclosures for the year ended December 31, 2026.
ASU 2025-06 Targeted Improvements to the Accounting of Internal-Use Software			In September 2025, the FASB issued guidance on accounting for capitalization of development costs for internal-use software under ASC Subtopic 350-40 and the transition approaches to use.			Effective for annual reporting periods beginning after December 15, 2027.			The Company is currently evaluating the impact the guidance will have on its results of operations, financial position, cash flows, and disclosures for the year ended December 31, 2028.
ASU 2025-10 Accounting for Government Grants Received By Business Entities			In December 2025, the FASB issued guidance on accounting for government grants received by business entities that are related to an asset (purchase, construction, or acquisition of a long-lived asset or inventory) or income (reimbursements to a business entity for operating expenses).			Effective for annual reporting periods beginning after December 15, 2028.			The Company is currently evaluating the impact the guidance will have on its results of operations, financial position, cash flows, and disclosures for the year ended December 31, 2029.

Cash, cash equivalents and restricted cash

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Restricted cash represents deposits held by the Company’s captive insurance company that is required by state insurance regulations to remain in the captive insurance company. The Company had restricted cash of $15.5 million and $16.7 million at December 31, 2025 and 2024, respectively.

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Revenue recognition

Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer and excludes any sales incentives and amounts collected on behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents revenues net of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.

The electric and natural gas distribution segments generate revenue from the sales of electric and natural gas products and services, which includes retail and transportation services. These segments establish a customer's retail or transportation service account based on the customer's application/contract for service, which indicates approval of a contract for service. The contract identifies an obligation to provide service in exchange for delivering or standing ready to deliver the identified commodity; and the customer is obligated to pay for the service as provided in the applicable tariff. The product sales are based on a fixed rate that includes a base and per-unit rate, which are included in approved tariffs as determined by state or federal regulatory agencies. The quantity of the commodity consumed or transported determines the total per-unit revenue. The service provided, along with the product consumed or transported, are a single performance obligation because both are required in combination to successfully transfer the contracted product or service to the customer. Revenues are recognized over time as customers receive and consume the products and services. The method of measuring progress toward the completion of the single performance obligation is on a per-unit output method basis, with revenue recognized based on the direct measurement of the value to the customer of the goods or services transferred to date. For contracts governed by the Company’s utility tariffs, amounts are billed monthly with the amount due between 15 and 22 days of receipt of the invoice depending on the applicable state’s tariff. For other contracts not governed by tariff, payment terms are net 30 days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.

The pipeline segment generates revenue from providing natural gas transportation and underground storage services, as well as other energy-related services to both third parties and internal customers, largely the natural gas distribution segment. The pipeline segment establishes a contract with a customer based upon the customer’s request for firm or interruptible natural gas transportation or storage service(s). The contract identifies an obligation for the segment to provide the requested service(s) in exchange for consideration from the customer over a specified term. Depending on the type of service(s) requested and contracted, the service provided may include transporting or storing an identified quantity of natural gas and/or standing ready to deliver or store an identified quantity of natural gas. Natural gas transportation and storage revenues are based on fixed rates, which may include reservation fees and/or per-unit commodity rates. The services provided by the segment are generally treated as single performance obligations satisfied over time simultaneous to when the service is provided and revenue is recognized. Rates for the segment’s regulated services are based on its FERC approved tariff or customer negotiated rates, and rates for its non-regulated services are negotiated with its customers and set forth in the contract. For contracts governed by the company’s tariff, amounts are billed on or before the ninth business day of the following month and the amount is due within 12 days of receipt of the invoice. For other contracts not governed by the tariff, payment terms are net 30 days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.

The Company recognizes all other revenues when services are rendered or goods are delivered.

Legal costs

The Company generally expenses external legal fees as they are incurred unless it has specific circumstances to defer, such as probable recovery in a rate proceeding.

Receivables and allowance for expected credit losses

Receivables consist primarily of trade receivables from the sale of goods and services net of expected credit losses. The Company's trade receivables are all due in 12 months or less. The total balance of receivables past due 90 days or more was $3.6 million at both December 31, 2025 and 2024.

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The Company's expected credit losses are determined through a review using historical credit loss experience, changes in asset specific characteristics, current conditions and reasonable and supportable future forecasts, among other specific account data, and is performed at least quarterly. The Company develops and documents its methodology to determine its allowance for expected credit losses at each of its reportable business segments. Risk characteristics used by the business segments may include customer mix, knowledge of customers and general economic conditions of the various local economies, among others. Specific account balances are written off when management determines the amounts to be uncollectible. Management has reviewed the balance reserved through the allowance for expected credit losses and believes it is reasonable.

Details of the Company's expected credit losses were as follows:

			Electric			Natural gas distribution			Pipeline			Total
			(In thousands)
At December 31, 2022			$	375		$	1,615		$	2		$	1,992
Current expected credit loss provision			1,645			5,777			—			7,422
Less write-offs charged against the allowance			1,994			7,355			2			9,351
Credit loss recoveries collected			388			1,152			—			1,540
At December 31, 2023			414			1,189			—			1,603
Current expected credit loss provision			1,891			4,667			—			6,558
Less write-offs charged against the allowance			2,218			5,709			—			7,927
Credit loss recoveries collected			386			1,219			—			1,605
At December 31, 2024			473			1,366			—			1,839
Current expected credit loss provision			2,197			4,723			—			6,920
Less write-offs charged against the allowance			2,559			5,782			—			8,341
Credit loss recoveries collected			395			1,136			—			1,531
At December 31, 2025			$	506		$	1,443		$	—		$	1,949

Receivables also consist of accrued unbilled revenue representing revenues recognized in excess of amounts billed. Accrued unbilled revenue within the electric and natural gas distribution segments was $128.1 million and $143.2 million at December 31, 2025 and 2024, respectively.

Inventories and natural gas in storage

Natural gas in storage is generally valued at lower of cost or market using the last-in, first-out method or lower of cost or net realizable value using the average cost or first-in, first-out method. The majority of all other inventories are valued at the lower of cost or net realizable value using the average cost method. The portion of the cost of natural gas in storage expected to be used within 12 months was included in inventories. Inventories at December 31 consisted of:

			2025			2024
			(In thousands)
Natural gas in storage (current)			$	34,333		$	40,073
Fuel stock			4,719			4,867
Total			$	39,052		$	44,940

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in noncurrent assets - other and was $47.8 million and $48.5 million at December 31, 2025 and 2024, respectively.

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Property, plant and equipment

Additions to property, plant and equipment are recorded at cost. When regulated assets are retired or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, the resulting gains or losses are recognized as a component of income.

The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, on certain contracting services projects associated with its other operations. The amount of AFUDC for the years ended December 31 was as follows:

			2025			2024			2023
			(In thousands)
AFUDC - borrowed			$	7,425		$	10,964		$	10,035
AFUDC - equity			$	2,301		$	2,251		$	1,894

Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets.

The Company collects removal costs for certain plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities on the Consolidated Balance Sheets.

Impairment of long-lived assets, excluding goodwill

The Company reviews the carrying values of its long-lived assets, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The Company tests long-lived assets for impairment at a level significantly lower than that of goodwill impairment testing. Long-lived assets or groups of assets that are evaluated for impairment at the lowest level of largely independent identifiable cash flows at an individual operation or group of operations collectively serving a local market. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. The impairments are recorded in operation and maintenance expense on the Consolidated Statements of Income.

No impairment losses were recorded in 2025, 2024 or 2023. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.

Regulatory assets and liabilities

The Company is subject to various state and federal agency regulations. The accounting policies followed by the Company are generally subject to the Uniform System of Accounts of the FERC as well as the provisions of ASC 980 - Regulated Operations. These accounting policies differ in some respects from those used by the Company's non-regulated businesses.

The Company accounts for certain income and expense items under the provisions of regulatory accounting, which requires the Company to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively. The Company records regulatory assets or liabilities at the time the Company determines the amounts to be recoverable in current or future rates. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commission. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which the Company completes in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. As of December 31, 2025, the only operating segment with goodwill was the natural gas distribution segment. For more information on the Company's operating segments, see Note 14.

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Goodwill impairment, if any, is measured by comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the goodwill of the reporting unit is not impaired. If the carrying value of a reporting unit exceeds its fair value, the Company must record an impairment loss for the amount that the carrying value of the reporting unit, including goodwill, exceeds the fair value of the reporting unit. For the years ended December 31, 2025, 2024 and 2023, the carrying amount of goodwill at the natural gas distribution segment, was $345.7 million. There have been no impairment losses recorded.

Investments

The Company's investments include the cash surrender value of life insurance policies, insurance contracts, mortgage-backed securities and U.S. Treasury securities. The Company measures its investment in the insurance contracts at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive loss. For more information, see Notes 8 and 15.

Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.

Derivative instruments

The Company enters into commodity price derivative contracts in order to minimize the price volatility associated with customer natural gas costs at its natural gas distribution segment. These derivatives are not designated as hedging instruments and are recorded in the Consolidated Balance Sheets at fair value. Changes in the fair value of these derivatives along with any contract settlements are recorded each period in regulatory assets or liabilities in accordance with regulatory accounting. The Company does not enter into any derivatives for trading or other speculative purposes.

The Company did not have any material commodity price derivative contracts at December 31, 2025 or 2024.

Leases

Lease liabilities and their corresponding right-of-use assets are recorded based on the present value of lease payments over the expected lease term. The Company recognizes leases with an original lease term of 12 months or less in income on a straight-line basis over the term of the lease and does not recognize a corresponding right-of-use asset or lease liability. The Company determines the lease term based on the non-cancelable and cancelable periods in each contract. The non-cancelable period consists of the term of the contract that is legally enforceable and cannot be canceled by either party without incurring a significant penalty. The cancelable period is determined by various factors that are based on who has the right to cancel a contract. If only the lessor has the right to cancel the contract, the Company will assume the contract will continue. If the lessee is the only party that has the right to cancel the contract, the Company looks to asset, entity and market-based factors. If both the lessor and the lessee have the right to cancel the contract, the Company assumes the contract will not continue.

The discount rate used to calculate the present value of the lease liabilities is based upon the implied rate within each contract. If the rate is unknown or cannot be determined, the Company uses an incremental borrowing rate, which is determined by the length of the contract, asset class and the Company's borrowing rates, as of the commencement date of the contract.

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Asset retirement obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a regulatory asset or liability.

Stock-based compensation

The Company determines compensation expense for stock-based awards based on the estimated fair values at the grant date and recognizes the related compensation expense over the vesting period. The Company uses the straight-line amortization method to recognize compensation expense related to RSUs, which only has a service condition. This method recognizes stock compensation expense on a straight-line basis over the requisite service period for the entire award. The Company recognized compensation expense related to PSAs that vest based on performance metrics and service conditions on a straight-line basis over the service period. Inception-to-date expense was adjusted based upon the determination of the potential achievement of the performance target at each reporting date. The Company recognizes compensation expense related to PSAs with market-based performance metrics on a straight-line basis over the requisite service period. Outstanding PSAs were converted to RSUs in connection with the completed separation of Knife River through the spinoff.

The Company records the compensation expense for RSUs and PSAs using an estimated forfeiture rate. The estimated forfeiture rate is calculated based on an average of actual historical forfeitures. The Company also performs an analysis of any known factors at the time of the calculation to identify any necessary adjustments to the average historical forfeiture rate. At the time actual forfeitures become more than estimated forfeitures, the Company records compensation expense using actual forfeitures.

Earnings per share

Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share is computed by dividing net income by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of nonvested PSAs and RSUs, as well as potentially issuable shares pursuant to FSAs using the treasury stock method.

Common stock outstanding includes issued shares less shares held in treasury. As a result of the 2023 Knife River separation, the Company retained legal ownership of 538,921 shares of the Company's common stock that were historically owned by a subsidiary of Knife River and recorded in Treasury stock at cost. Following the separation, the 538,921 treasury shares were retired. The 538,921 shares of treasury stock did not have an impact on weighted-average shares outstanding, as they were not outstanding prior to being retired. Net income was the same for both the basic and diluted earnings per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings per share calculations follows:

			2025			2024			2023
			(In thousands, except per share amounts)
Weighted average common shares outstanding - basic			204,291			203,867			203,640
Effect of dilutive PSAs, RSUs, and FSAs			1,009			786			298
Weighted average common shares outstanding - diluted			205,300			204,653			203,938
Earnings per share - basic:
Income from continuing operations			$	.94		$	.89		$	1.62
Discontinued operations, net of tax			(.01)			.49			.42
Earnings per share - basic			$	0.93		$	1.38		$	2.04
Earnings per share - diluted:
Income from continuing operations			$	.93		$	.88		$	1.62
Discontinued operations, net of tax			—			.49			.41
Earnings per share - diluted			$	0.93		$	1.37		$	2.03
Shares excluded from the calculation of diluted earnings per share			—			—			—
Dividends declared per common share			$	.5400		$	.5100		$	.6950

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Income taxes

The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as regulatory liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.

The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.

The Company records uncertain tax positions in accordance with accounting guidance on accounting for income taxes on the basis of a two-step process in which (1) the Company determines whether it is more-likely-than-not that the tax position will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, the Company recognizes the largest amount of the tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority. Tax positions that do not meet the more-likely-than-not criteria are reflected as a tax liability. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.

Note 3 - Discontinued Operations

On May 31, 2023, the Company completed the separation of Knife River, its former construction materials and contracting segment, into a new independent publicly-traded company. The separation was achieved through the Company's pro-rata distribution of approximately 90 percent of the outstanding shares of Knife River to the Company's common stockholders. To effect the separation, the Company distributed to its stockholders one share of Knife River common stock for every four shares of the Company's common stock held on May 22, 2023, the record date for the distribution, with the Company retaining approximately 10 percent, or 5.7 million shares of Knife River common stock immediately following the separation. In November 2023, the Company completed the tax-free exchange of its retained shares and recognized a gain of $186.6 million, which was reflected in continuing operations because the Company did not have continuing significant involvement in Knife River. The separation of Knife River was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

On October 31, 2024, the Company completed the separation of Everus, its former construction services segment, into a new independent, publicly-traded company. The Company's board of directors approved the distribution of all the outstanding shares of Everus common stock to the Company's stockholders. Stockholders of the Company received one share of Everus common stock for every four shares of the Company's common stock held as of the close of business on October 21, 2024, the record date for the distribution. The separation of Everus was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.

As a result of the separations, the historical results of operations are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the Company, which did not meet the criteria for discontinued operations. The Company’s consolidated financial statements and accompanying notes for prior periods have been restated. For the comparative periods, Everus' operations are only reflected through October 2024 compared to the full year in 2023 and Knife River's operations are only reflected through May 2023.

On April 25, 2023, Knife River issued $425.0 million of senior notes, pursuant to an indenture, due in 2031 to qualified institutional buyers. Knife River also entered into a new credit agreement which provided a revolving credit facility in an initial amount of up to $350.0 million and a senior secured term loan facility in an amount up to $275.0 million. The net proceeds from the notes offering, revolving credit facility and the term loan were used to repay $825.0 million of Knife River's intercompany obligations owed to Centennial. Centennial used the entirety of these proceeds from Knife River to repay a portion of its existing third-party indebtedness.

As a result of the separation of Knife River, the Company retained legal ownership of 538,921 shares of the Company's common stock that were historically owned by a subsidiary of Knife River and recorded in Treasury stock at cost. Following the separation of Knife River, the 538,921 treasury shares were retired.

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The Company provided to Knife River and Knife River provided to the Company transition services in accordance with the transition services agreement entered into on May 31, 2023. For the twelve months ended December 31, 2024 and 2023, the Company received $1.5 million and $2.9 million, respectively; and paid $159,000 and $823,000, respectively, for these related activities. All transition services were completed as of October 2024.

The Company provided and will provide to Everus and Everus provided and will provide to the Company transition services in accordance with the transition services agreement entered into on October 31, 2024. For the twelve months ended December 31, 2025 and 2024, the Company received $7.9 million, which include certain software costs and $727,000, respectively; and paid $49,000 and $47,000, respectively, for these related activities. The transition services are expected to be complete as of March 2026.

Separation related costs of $1.0 million, $41.7 million and $58.6 million net of tax, were incurred during the twelve months ended December 31, 2025, 2024 and 2023, respectively. Certain separation costs incurred are presented in discontinued operations, net of tax in the Consolidated Statements of Income. These charges primarily relate to transaction and third-party support costs, one-time business separation fees and related tax charges.

The Company had no assets or liabilities related to the discontinued operations of Everus on its balance sheet as of December 31, 2025 or 2024.

The reconciliation of the major classes of income and expense constituting pretax income from discontinued operations to the after-tax income from discontinued operations on the Consolidated Statements of Income were as follows:

			2025			2024			2023
			(In thousands)
Operating revenues			$	2		$	2,377,332		$	3,589,251
Operating expenses			1,160			2,241,162			3,422,393
Operating (loss) income			(1,158)			136,170			166,858
Other income			—			12,446			10,599
Interest expense			—			7,118			47,229
(Loss) income from discontinued operations before income taxes			(1,158)			141,498			130,228
Income tax (benefit) expense			(146)			41,463			45,638
Discontinued operations, net of tax			$	(1,012)		$	100,035		$	84,590

Note 4 - Revenue from Contracts with Customers

Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer and excludes any sales incentives and amounts collected on behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents revenues net of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.

As part of the adoption of ASC 606 - Revenue from Contracts with Customers, the Company elected the practical expedient to recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that the Company otherwise would have recognized is 12 months or less.

MDU Resources Group, Inc. Form 10-K 81

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Disaggregation

In the following table, revenue is disaggregated by the type of customer or service provided. The Company believes this level of disaggregation best depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. The table also includes a reconciliation of the disaggregated revenue by reportable segments. For more information on the Company's business segments, see Note 14.

Year ended December 31, 2025			Electric			Natural gas distribution			Pipeline			Other			Total
			(In thousands)
Residential utility sales			$	137,673		$	654,793		$	—		$	—		$	792,466
Commercial utility sales			187,097			436,431			—			—			623,528
Industrial utility sales			38,066			44,183			—			—			82,249
Other utility sales			7,537			—			—			—			7,537
Natural gas transportation			—			66,978			191,542			—			258,520
Natural gas storage			—			—			23,270			—			23,270
Other			74,159			62,894			14,185			722			151,960
Intersegment eliminations			(553)			(345)			(74,992)			(722)			(76,612)
Revenues from contracts with customers			443,979			1,264,934			154,005			—			1,862,918
Other revenues			(6,202)			18,196			154			—			12,148
Total external operating revenues			$	437,777		$	1,283,130		$	154,159		$	—		$	1,875,066

Year ended December 31, 2024			Electric			Natural gas distribution			Pipeline			Other			Total
			(In thousands)
Residential utility sales			$	140,054		$	646,049		$	—		$	—		$	786,103
Commercial utility sales			171,760			399,087			—			—			570,847
Industrial utility sales			42,883			42,588			—			—			85,471
Other utility sales			7,910			—			—			—			7,910
Natural gas transportation			—			60,645			174,623			—			235,268
Natural gas storage			—			—			23,690			—			23,690
Other			59,288			40,703			13,139			195			113,325
Intersegment eliminations			(72)			(130)			(69,222)			(195)			(69,619)
Revenues from contracts with customers			421,823			1,188,942			142,230			—			1,752,995
Other revenues			(7,417)			12,033			367			—			4,983
Total external operating revenues			$	414,406		$	1,200,975		$	142,597		$	—		$	1,757,978

Year ended December 31, 2023			Electric			Natural gas distribution			Pipeline			Other			Total
			(In thousands)
Residential utility sales			$	136,274		$	724,600		$	—		$	—		$	860,874
Commercial utility sales			170,321			442,507			—			—			612,828
Industrial utility sales			43,063			45,205			—			—			88,268
Other utility sales			7,270			—			—			—			7,270
Natural gas transportation			—			52,465			145,297			—			197,762
Natural gas storage			—			—			18,254			—			18,254
Other			54,508			15,141			13,874			119			83,642
Intersegment eliminations			(138)			(301)			(62,533)			(119)			(63,091)
Revenues from contracts with customers			411,298			1,279,617			114,892			—			1,805,807
Other revenues			(10,261)			7,619			187			—			(2,455)
Total external operating revenues			$	401,037		$	1,287,236		$	115,079		$	—		$	1,803,352

82 MDU Resources Group, Inc. Form 10-K

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Remaining performance obligations

The remaining performance obligations at the pipeline segment include firm transportation and storage contracts with fixed pricing and fixed volumes. The Company has applied the practical expedient that does not require additional disclosures for contracts with an original duration of less than 12 months to certain firm transportation and non-regulated contracts. The Company's firm transportation and storage contracts included in the remaining performance obligations have weighted average remaining durations of less than four years and one year, respectively.

At December 31, 2025, the Company expects to recognize revenue in future periods from remaining performance obligations, as follows:

12 months or less			Next 13-24 months			25 months or more			Total
(In Millions)
$	86.8		$	79.1		$	365.6		$	531.5

Note 5 - Property, Plant and Equipment

Property, plant and equipment at December 31 was as follows:

			2025			2024			Weighted Average Depreciable Life in Years
			(Dollars in thousands, where applicable)
Electric:
Generation			$	1,329,301		$	1,014,906		49
Distribution			585,328			546,121			45
Transmission			701,287			662,466			65
CWIP			62,415			81,316			0
Other			190,049			176,007			14
Natural gas distribution:
Distribution			3,202,171			2,955,435			54
Transmission			147,118			146,710			54
Storage			44,427			43,700			37
General			234,752			229,034			13
CWIP			82,858			74,207			0
Other			292,428			282,007			15
Pipeline:
Transmission			1,200,423			1,173,259			46
Storage			64,230			61,369			53
CWIP			47,044			29,629			0
Other			76,994			73,749			17
Other:
Land and other			4,147			4,148			NM
Less accumulated depreciation and amortization			2,304,787			2,209,771
Net property, plant and equipment			$	5,960,185		$	5,344,292
NM - not meaningful

MDU Resources Group, Inc. Form 10-K 83

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Note 6 - Regulatory Matters

Regulatory assets & liabilities

The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:

			Estimated Recovery or Refund Period			*			2025			2024
									(In thousands)
Regulatory assets:
Current:
Environmental compliance programs			Up to 1 year						$	78,784		$	76,964
Conservation programs			Up to 1 year						29,148			19,123
Natural gas costs recoverable through rate adjustments			Up to 1 year						22,897			91,091
Decoupling mechanisms			Up to 1 year						17,091			6,767
Cost recovery mechanisms			Up to 1 year						13,460			5,114
Electric fuel and purchased power deferral			Up to 1 year						6,902			9,662
Other			Up to 1 year						11,297			6,715
									179,579			215,436
Noncurrent:
Pension and postretirement benefits			**						135,222			142,064
Cost recovery mechanisms			Up to 23 years						63,328			76,542
Plant costs/asset retirement obligations			Over plant lives						48,352			47,042
Manufactured gas plant site remediation			-						28,411			27,964
Taxes recoverable from customers			Over plant lives						12,250			12,221
Covid-19 deferred costs			Up to 3 years						3,761			4,167
Long-term debt refinancing costs			Up to 37 years						1,799			2,011
Electric fuel and purchased power deferral			-						—			4,349
Other			Up to 13 years						4,095			5,990
									297,218			322,350
Total regulatory assets									$	476,797		$	537,786
Regulatory liabilities:
Current:
Environmental compliance			Up to 1 year						$	89,306		$	72,387
Natural gas costs refundable through rate adjustments			Up to 1 year						47,130			45,427
Margin sharing			Up to 1 year						3,946			4,156
Taxes refundable to customers			Up to 1 year						2,301			2,163
Provision for rate refund			Up to 1 year						1,780			3,677
Conservation programs			Up to 1 year						733			2,082
Cost recovery mechanisms			Up to 1 year						115			1,720
Other			Up to 1 year						3,273			5,555
									148,584			137,167
Noncurrent:
Plant removal and decommissioning costs			Over plant lives						224,313			217,603
Taxes refundable to customers			Over plant lives						176,665			185,402
Cost recovery mechanisms			Up to 16 years						41,323			30,354
Accumulated deferred investment tax credit			Over plant lives						22,663			18,788
Pension and postretirement benefits			**						4,776			4,862
Other			Up to 12 years						2,589			2,161
									472,329			459,170
Total regulatory liabilities									$	620,913		$	596,337
Net regulatory position									$	(144,116)		$	(58,551)

*Estimated recovery or refund period for amounts currently being recovered or refunded in rates to customers.

**    Recovered as expense is incurred or cash contributions are made.

84 MDU Resources Group, Inc. Form 10-K

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As of December 31, 2025 and 2024, approximately $174.3 million and $181.2 million, respectively, of regulatory assets were not earning a rate of return but are expected to be recovered from customers in future rates. These assets are largely comprised of the unfunded portion of pension and postretirement benefits, asset retirement obligations, certain pipeline integrity costs and the estimated future cost of manufactured gas plant site remediation.

The Company is subject to environmental compliance regulations in certain states which require natural gas distribution companies to reduce overall GHG emissions to certain thresholds as established by each applicable state. Compliance with these standards may be achieved through increased energy efficiency and conservation measures, purchased emission allowances and offsets and purchases of low carbon fuels. Emission allowances are allocated by the respective states to the Company at no cost, of which a portion is required to be sold at auction. The compliance costs for these regulations and the revenues from the sale of the allocated emissions allowances are passed through to customers in rates and the Company has, accordingly, deferred the environmental compliance costs as a regulatory asset and proceeds from the sale of allowances as a regulatory liability.

If, for any reason, the Company's regulated businesses cease to meet the criteria for application of regulatory accounting for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be written off and included in the statement of income or accumulated other comprehensive loss in the period in which the discontinuance of regulatory accounting occurs.

Regulatory proceedings

The Company regularly reviews the need for electric and natural gas rate changes in each of the jurisdictions in which service is provided. The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed by regulators. Certain regulatory proceedings and cases may also contain recurring mechanisms that can have an annual true-up. Examples of these recurring mechanisms include: infrastructure riders, transmission trackers, renewable resource cost adjustment riders, as well as weather normalization and decoupling mechanisms. The Company is unable to predict the ultimate outcome of these matters, the timing of final decisions of the various regulators and courts, or the effect on the Company's results of operations, financial position or cash flows.

The following table summarizes the Company's significant regulatory proceedings and cases by jurisdiction:

Segment

State

Filing Date

Annual Revenue Increase (%) *

Annual Revenue Increase (in millions) *

ROE

Status

Key Drivers and Additional Information

General Rate Cases Pending

Electric

Wyoming

June 30, 2025

18.6

%

$5.8

9.7

%

Settlement agreement filed January 23, 2026 Final rates requested to be effective April 1, 2026

•Increases in operation and maintenance expense •Investments made since the last rate case •Corresponding depreciation on those infrastructure investments •Settlement includes a stipulation to withdraw the requested Reliability and Safety Rider

Electric

Montana

September 30, 2025

20.2

%

$14.1

10.8

%

Pending

•Investments, including Badger Wind Farm •Corresponding depreciation on those investments •Increased operation and maintenance expense

Natural Gas Distribution

Oregon

November 25, 2025

15.8

%

$16.4

10.4

%

Pending

•Rate base growth •Growth in operations and maintenance expense •Growth in depreciation expense associated with new investments in rate base

MDU Resources Group, Inc. Form 10-K 85

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Segment

State

Filing Date

Annual Revenue Increase (%) *

Annual Revenue Increase (in millions) *

ROE

Status

Key Drivers and Additional Information

General Rate Cases Finalized

Natural Gas Distribution

Washington

March 29, 2024

7.9% 2.6%

$29.8 $10.8

9.5

%

Approved February 24, 2025 Final rates effective March 5, 2025 $3.7M revenue reduction effective June 1, 2025 Final rates effective March 1, 2026, subject to provisional plant review

•Multi-year rate case •Infrastructure investments necessary to provide safe and reliable service •Higher operating costs due to inflation •$3.7M revenue reduction was driven by forecasted plant that was not placed in service by December 31, 2024

Natural Gas Distribution

Idaho

May 30, 2025

4.2

%

$13.0

9.5

%

Approved Final rates effective January 1, 2026

•Increased operating expenses •Costs associated with plant additions •Revenues necessary to produce a fair rate of return to enable continued safe and reliable service

Natural Gas Distribution

Montana

July 15, 2024

8.6

%

$7.3

9.6

%

Approved Interim rates of $7.7M effective February 1, 2025 Final rates effective November 1, 2025

•Investments in system upgrades pipeline replacement projects enhancing the reliability, safety and integrity of the natural gas system •Increased costs to operate and maintain that system

Natural Gas Distribution

Wyoming

October 31, 2024

11.7

%

$2.1

9.65

%

Approved Final rates effective August 1, 2025

•Investments in system upgrades and pipeline replacement projects enhancing the reliability, safety and integrity of the natural gas system •Increased costs to operate and maintain that system

*Annual revenue increase and percent increase for general rate cases pending and general rate cases finalized, reflects the final approved amount or the amount reflected in the most recent settlement agreement, if applicable.

Segment

State

Filing Date

Annual Revenue Increase (in millions)

Status

Key Drivers and Additional Information

Other Filings

Electric

North Dakota

July 15, 2025

$7.2

Approved Rates effective November 1, 2025

Transmission Cost Adjustment Rider •Allows recovery of transmission costs, including capital investments, and associated revenue

Natural Gas Distribution

Wyoming

August 15, 2025

N/A

Pending

System Safety and Integrity Rider •Would allow Montana-Dakota to recover costs and expenses associated with a pipeline replacement program

Electric

Montana

September 30, 2025

N/A

Pending

Systems Management Cost Adjustment Mechanism •Recovery of transmission and wildfire related costs

Electric

North Dakota

October 31, 2025

$25.3

Approved Rates effective February 1, 2026

Renewable Resource Cost Adjustment •Allows for annual adjustments for recent projected capital costs and related expenses for projects determined to be recoverable •Update includes Badger Wind Farm

Electric

South Dakota

October 31, 2025

$1.1

Pending

Infrastructure Rider •Allows annual adjustments for recent projected capital costs and related expenses for projects determined to be recoverable •Update includes Badger Wind Farm

Note 7 - Environmental Allowances and Obligations

The Company's natural gas distribution segment acquires environmental allowances as part of its requirement to comply with environmental regulations in certain states. Allowances are allocated by the respective states to the Company at no cost and additional allowances are required to be purchased as needed based on the requirements in the respective states. The segment records purchased and allocated environmental allowances at weighted average cost under the inventory method of accounting. Environmental allowances are included as Current environmental allowances and Environmental allowances in current and noncurrent assets on the Consolidated Balance Sheets.

86 MDU Resources Group, Inc. Form 10-K

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Environmental compliance obligations, which are based on GHG emissions, are measured at the carrying value of environmental allowances held plus the estimated value of additional allowances necessary to satisfy the compliance obligation. Environmental compliance obligations are included as Current environmental obligations and Environmental obligations in current and noncurrent liabilities on the Consolidated Balance Sheets.

The Company recognizes revenue from the sale of emissions allowances allocated under the environmental programs when the allowances are sold at auction. The revenues associated with the sale of these allowances are deferred as a component of the respective jurisdiction’s regulatory liability for environmental compliance.

As environmental allowances are surrendered, the segment reduces the associated environmental compliance assets and liabilities from the Consolidated Balance Sheets. The expenses and revenues associated with the Company’s environmental allowances and obligations are deferred as regulatory assets and liabilities and recognized as a component of purchased natural gas sold as recovered in customer rates. For more information on the Company’s regulatory assets and liabilities, see Note 6.

Note 8 - Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The fair value ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.

The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of insurance contracts, to satisfy its obligations under its unfunded, nonqualified defined benefit and defined contribution plans for executive officers and certain key management employees and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $67.4 million and $59.3 million at December 31, 2025 and 2024, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gain on these investments for the year ended December 31, 2025, 2024, and 2023 was $6.6 million, $5.9 million, and $7.4 million, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in Other income on the Consolidated Statements of Income. In the second quarter of 2025 the Company withdrew $5.0 million of cash in excess of 125 percent of the full funding amount, which had no effect on the cost basis of the investments held. In the first quarter of 2024 the Company withdrew $9.0 million of its cost basis, which reduced Investments on the Consolidated Balance Sheets.

The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as Investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in Accumulated other comprehensive loss on the Consolidated Balance Sheets. Details of available-for-sale securities were as follows:

December 31, 2025			Cost			Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
			(In thousands)
Mortgage-backed securities			$	8,539		$	28		$	204		$	8,363
U.S. Treasury securities			3,992			33			—			4,025
Total			$	12,531		$	61		$	204		$	12,388

December 31, 2024			Cost			Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
			(In thousands)
Mortgage-backed securities			$	7,933		$	4		$	383		$	7,554
U.S. Treasury securities			3,945			80			1			4,024
Total			$	11,878		$	84		$	384		$	11,578

MDU Resources Group, Inc. Form 10-K 87

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The Company's assets measured at fair value on a recurring basis were as follows:

			Fair Value Measurements at December 31, 2025, Using
			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs  (Level 3)			Balance at December 31, 2025
			(In thousands)
Assets:
Money market funds			$	—		$	9,839		$	—		$	9,839
Insurance contracts*			—			67,409			—			67,409
Available-for-sale securities:
Mortgage-backed securities			—			8,363			—			8,363
U.S. Treasury securities			—			4,025			—			4,025
Total assets measured at fair value			$	—		$	89,636		$	—		$	89,636

*The insurance contracts invest approximately 57 percent in fixed-income investments, 18 percent in common stock of large-cap companies, 10 percent in target date investments, 7 percent in common stock of mid-cap companies, 4 percent in common stock of small-cap companies, 3 percent in cash equivalents, and 1 percent in international investments.

			Fair Value Measurements at December 31, 2024, Using
			Quoted Prices in Active Markets for Identical Assets  (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs  (Level 3)			Balance at December 31, 2024
			(In thousands)
Assets:
Money market funds			$	—		$	12,879		$	—		$	12,879
Insurance contracts*			—			59,282			—			59,282
Available-for-sale securities:
Mortgage-backed securities			—			7,554			—			7,554
U.S. Treasury securities			—			4,024			—			4,024
Total assets measured at fair value			$	—		$	83,739		$	—		$	83,739

*The insurance contracts invest approximately 58 percent in fixed-income investments, 17 percent in common stock of large-cap companies, 8 percent in target date investments, 8 percent in common stock of mid-cap companies, 4 percent in common stock of small-cap companies, 4 percent in cash equivalents, and 1 percent in international investments.

The Company's money market funds are valued at the net asset value of shares held at the end of the period, based on published market quotations on active markets, or using other known sources including pricing from outside sources. The estimated fair value of the Company's mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources. The estimated fair value of the Company's insurance contracts are based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.

The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable.

88 MDU Resources Group, Inc. Form 10-K

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The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was categorized as Level 2 in the fair value hierarchy and was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:

			2025			2024
			(In thousands)
Carrying Amount			$	2,676,855		$	2,292,610
Fair Value			$	2,385,170		$	1,963,396

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

Note 9 - Debt

Due to the Knife River separation, Centennial repaid all of its outstanding debt in the second quarter of 2023, which was funded by the Knife River repayment and the Company entering into various new debt instruments. Refer to Note 3 for additional information related to the repayment of debt associated with the Knife River separation.

Certain debt instruments of the Company and its subsidiaries contain restrictive and financial covenants and cross-default provisions. In order to borrow under the respective debt agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions. Intermountain was not in compliance with its minimum interest coverage ratio for the period ended September 30, 2025, which constituted an event of default under the terms of the Intermountain NPAs. In addition, the event of default under the terms of the Intermountain NPAs constituted a cross-default under the terms of certain NPAs of MDU Energy Capital and revolving credit agreements held by the Company and Intermountain. Subsequent to September 30, 2025, Intermountain and MDU Energy Capital obtained waivers for this non-compliance from the holders of a majority of their respective outstanding notes, and Intermountain and the Company obtained waivers from the lenders of the revolving credit agreements, which collectively cured the impact of any events of default. The Company and its subsidiaries were in compliance with applicable covenants at December 31, 2025. In the event the Company or its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

Credit facilities

Montana-Dakota's commercial paper program is supported by a revolving credit agreement. While the amount of commercial paper outstanding does not reduce available capacity under the revolving credit agreement, Montana-Dakota does not issue commercial paper in an aggregate amount exceeding the available capacity under the credit agreement. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The commercial paper and revolving credit agreement borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of certain operations of Montana-Dakota.

The Company's borrowings under revolving credit agreements are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. All of the credit agreements contain customary covenants and provisions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.

Montana-Dakota On December 11, 2025, Montana-Dakota amended and restated its revolving credit agreement to extend the maturity date from October 18, 2028 to December 11, 2030. This amendment sets forth the terms and conditions under which the syndicate of lenders would make loans to or for the benefit of Montana-Dakota. These terms and conditions outline the pricing level and applicable facility fee for borrowings or letters of credit under the agreement. Montana-Dakota's revolving credit agreement supports its commercial paper program.

Cascade On December 11, 2025, Cascade amended and restated its revolving credit agreement to extend the maturity date from June 20, 2029 to December 11, 2030. This amendment sets forth the terms and conditions under which the syndicate of lenders would make loans to or for the benefit of Cascade. These terms and conditions outline the pricing level and applicable facility fee for borrowings or letters of credit under the agreement. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

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Intermountain On December 11, 2025, Intermountain amended and restated its revolving credit agreement to extend the maturity date from June 20, 2029 to December 11, 2030. This amendment sets forth the terms and conditions under which the syndicate of lenders would make loans to or for the benefit of Intermountain. These terms and conditions outline the pricing level, pricing level change date and applicable facility fee for borrowings or letters of credit under the agreement. Upon the pricing level change date, Intermountain is required under the agreement to deliver financial statements and officers compliance certificate to the assigned administrative agent. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

MDU Resources Group, Inc. On December 11, 2025, the Company amended and restated its revolving credit agreement to extend the maturity date from May 31, 2028 to December 11, 2030. This amendment sets forth the terms and conditions under which the syndicate of lenders would make loans to or for the benefit of MDU Resources Group, Inc. These terms and conditions outline the pricing level and applicable facility fee for borrowings or letters of credit under the agreement. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries:

Company			Debt-to-Total Capitalization Ratio			Provisions for Increased Borrowings, up to a maximum of:			Facility Limit			Amount Outstanding at December 31, 2025			Amount Outstanding at December 31, 2024			Letters of Credit at December 31, 2025			Expiration Date
						(In millions)
Montana-Dakota Utilities Co.			55		%	$	250.0		$	200.0		$	132.0		$	81.4		$	—		12/11/30
Cascade Natural Gas Corporation			50		%	$	225.0		$	175.0		$	96.5		$	64.6		$	2.2		12/11/30
Intermountain Gas Company			52		%	$	225.0		$	175.0		$	67.3		$	105.1		$	—		12/11/30
MDU Resources Group, Inc.			49		%	$	250.0		$	200.0		$	32.9		$	—		$	1.0		12/11/30

Long-term debt

Long-term Debt Outstanding Long-term debt outstanding was as follows:

			Weighted Average Interest Rate at December 31, 2025			2025			2024
						(In thousands)
Senior notes due on dates ranging from July 15, 2026 to June 15, 2062			4.76		%	$	2,010,000		$	1,947,000
Term loan agreements due on dates ranging from January 29, 2027 to April 1, 2039			4.68		%	310,900			65,600
Credit agreements due on December 11, 2030			5.17		%	196,700			169,700
Commercial paper supported by revolving credit agreement			4.00		%	132,000			81,400
Medium-term notes due on dates ranging from September 15, 2027 to March 16, 2029			7.32		%	35,000			35,000
Other notes due on November 30, 2038			6.00		%	329			346
Less unamortized debt issuance costs						8,074			6,436
Total long-term debt						2,676,855			2,292,610
Less current maturities						144,700			161,700
Net long-term debt						$	2,532,155		$	2,130,910

Montana-Dakota On July 11, 2024, Montana-Dakota issued $125.0 million of senior notes under a NPA with maturity dates of July 11, 2039 and July 11, 2054, at a weighted average interest rate of 5.96 percent. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments.

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On October 28, 2025, Montana-Dakota entered into a NPA to issue $250.0 million of senior notes, with maturity dates of October 28, 2035, October 28, 2040, and February 2, 2056, at a weighted average interest rate of 5.96 percent. On October 28, 2025, Montana-Dakota issued $150.0 million in senior notes under the NPA with the remaining $100.0 million issued on February 2, 2026. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. Other covenants include a minimum interest coverage ratio and restrictions on the sale of certain assets.

On December 30, 2025, Montana-Dakota entered into a $250.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of January 29, 2027. On February 3, 2026, Montana-Dakota paid down $100.0 million of the outstanding balance under the term loan agreement. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans, and investments.

Intermountain On July 15, 2025, Intermountain entered into a NPA to issue a total of $50.0 million of senior notes, with a maturity date of July 15, 2055, at an interest rate of 6.39 percent. On July 15, 2025, Intermountain issued $25.0 million in senior notes under the NPA with the remaining $25.0 million issued on November 14, 2025. This NPA is one of three distinct Intermountain NPAs that contain certain customary covenants, including a minimum interest coverage ratio.

WBI Energy Transmission On January 15, 2026, WBI Energy Transmission extended its $350.0 million uncommitted note purchase and private shelf agreement from December 22, 2025 to December 22, 2028, unless either party terminates such issuance right. WBI Energy Transmission had $235.0 million of notes outstanding at December 31, 2025, which reduced the remaining capacity under this uncommitted private shelf agreement to $115.0 million. The principal amount and interest rate of any series of shelf notes will be determined at the applicable time of issuance and purchase. On December 22, 2025, WBI Energy Transmission entered into a NPA to issue a total of $20.0 million of senior notes, with a maturity date of December 22, 2045, at an interest rate of 6.29 percent. This agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include a limitation on priority debt, restrictions on the sale of certain assets and the making of certain investments.

On April 1, 2024, WBI Energy Transmission entered into a $60.0 million term loan agreement with an interest rate of 4.52 percent and a maturity date of April 1, 2039, with the principal to be repaid in equal annual installments of $4.0 million each, beginning March 2025 and continuing through the maturity date. The agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments.

WBI Energy Transmission's ratio of total debt to total capitalization at December 31, 2025 was 39 percent.

Schedule of Debt Maturities Long-term debt maturities, which excludes unamortized debt issuance costs and discount, for the five years and thereafter following December 31, 2025, were as follows:

			2026			2027			2028			2029			2030			Thereafter
			(In thousands)
Long-term debt maturities			$	144,700		$	274,700		$	79,700		$	74,700		$	475,400		$	1,635,729

Note 10 - Asset Retirement Obligations

The Company records obligations related to retirement costs of natural gas distribution lines, natural gas transmission lines, natural gas storage wells, decommissioning of certain electric generating facilities, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other obligations as asset retirement obligations.

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A reconciliation of the Company's liability, which the current portion is included in other accrued liabilities on the Consolidated Balance Sheets, for the years ended December 31 was as follows:

			2025			2024
			(In thousands)
Balance at beginning of year			$	406,647		$	385,154
Liabilities incurred*			7,474			2,721
Liabilities settled			(2,867)			(5,271)
Accretion expense**			20,883			19,655
Revisions in estimates			(221)			4,388
Balance at end of year			$	431,916		$	406,647

*2025 includes $4.8 million for the future decommissioning of Badger Wind Farm.

**Includes $20.9 million and $19.6 million in 2025 and 2024, respectively, recorded to regulatory assets.

The 2024 revisions in estimates consist principally of updated asset retirement obligation costs resulting from decommissioning studies performed for electric generating facilities at the electric segment.

The Company believes that largely all expenses related to asset retirement obligations at the Company's regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets. For more information on the Company's regulatory assets and liabilities, see Note 6.

Note 11 - Equity

The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly dividends for 88 consecutive years. For the years ended December 31, 2025, 2024 and 2023, dividends declared on common stock were $.5400, $.5100 and $.6950 per common share, respectively. Dividends on common stock are paid quarterly to the stockholders as of the record date. For the years ended December 31, 2025, 2024 and 2023, the dividends declared to common stockholders were $110.3 million, $103.9 million and $141.5 million, respectively.

The declaration and payment of dividends of the Company is at the sole discretion of the board of directors. In addition, the Company's subsidiaries are generally restricted to paying dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.

Certain credit agreements and regulatory limitations of the Company's subsidiaries also contain restrictions on dividend payments. The most restrictive limitation requires the Company's subsidiaries not to permit the ratio of funded debt to capitalization to be greater than 65 percent. Based on this limitation, approximately $1.5 billion of the net assets of the Company's subsidiaries, which represents common stockholders' equity including retained earnings, would be restricted from use for dividend payments at December 31, 2025.

The Company may sell any combination of common stock and debt securities if warranted by market conditions and the Company's capital requirements. Any public offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.

At-the-Market Offering Program On August 7, 2025, the Company entered into an EDA pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $400.0 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs. Since the establishment of the ATM offering program, the Company did not issue common stock pursuant to the EDA nor enter into any FSAs related to the EDA.

Equity Forward Sale Agreements On December 5, 2025, the Company completed a follow-on public offering of 10,152,284 shares of the Company's common stock at a public offering price of $19.70 per share. In addition, on December 23, 2025, the underwriters exercised their option to purchase 1,522,842 additional shares of common stock. Pursuant to the FSAs entered into in connection with the offering, the Company has discretion to settle the FSAs on one or more settlement dates prior to December 6, 2027, subject to certain price adjustments as set forth in the FSAs as well as adjustments for transaction and other associated fees. The FSAs will be physically settled with shares of common stock issued by the Company, unless the Company elects to settle the FSAs in net cash or net shares, subject to certain conditions. If the Company elects to physically settle the FSAs, the Company will physically issue shares of common stock to the banking counterparties at the then-applicable forward sale price and receive proceeds at that time.

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At December 31, 2025, the Company could have settled all of its outstanding FSAs with physical delivery of 11,675,126 shares of common stock to the banking counterparties in exchange for cash of approximately $221.1 million. If the FSAs had been net cash or net share settled at December 31, 2025, the Company estimates that the counterparties, in aggregate, would have been entitled to a net settlement of $6.8 million or 349,596 shares, respectively.

The forward price used to determine amounts due at settlement is calculated based on the public offering price, subject to transaction and other associated fees, adjusted by the overnight bank funding rate, less a spread, and less expected dividends on the Company's common stock during the period the FSAs are outstanding.

The FSAs are indexed to the Company's stock and meets the other requirements for equity classification. As a result of the equity classification, no gain or loss is recognized in earnings associated with the subsequent changes in fair value of the FSAs. Stockholders' equity equal to cash proceeds net of deferred issuance costs will be recorded upon settlement.

FSAs earnings per share dilution Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in the Company's diluted earnings per share calculation using the treasury stock method. Share dilution occurs when the average market price of the Company's stock during the reporting period is higher than the then-applicable forward sale price at the end of the reporting period. For more information on earnings per share, see Note 2.

The K-Plan provides participants the option to invest in the Company's common stock. For the years ended December 31, 2025, 2024 and 2023, the K-Plan purchased shares of common stock on the open market. At December 31, 2025, there were 2.4 million shares of common stock reserved for original issuance under the K-Plan.

The Company currently has 2.0 million shares of preferred stock authorized to be issued with a $100 par value. At December 31, 2025 and 2024, there were no shares outstanding.

Note 12 - Stock-Based Compensation

The Company has stock-based compensation plans under which it is currently authorized to grant RSUs and other stock awards. As of December 31, 2025, there were 1.7 million remaining shares available to grant under these plans. The Company either purchases shares on the open market or issues new shares of common stock to satisfy the vesting of stock-based awards.

Separations of Knife River and Everus

In connection with the completed separations of Knife River and Everus through spinoffs, the provisions of the existing compensation plans required adjustments to the number and terms of outstanding employee time-vested RSUs and PSAs to preserve the intrinsic value of the awards immediately prior to each separation. The outstanding awards will continue to vest over the original vesting period, which is generally three years from the grant date. The outstanding PSAs in place at the time of the Knife River spinoff were modified to no longer be subject to performance-based vesting conditions. The number of PSAs were first adjusted for performance. The combined performance factors were determined based on the performance of the Company as of December 31, 2022. Outstanding awards at the time of the spinoffs were converted into awards of the holder’s employer following each separation. The Company incurred $1.7 million of incremental compensation expense related to the conversion of the RSUs associated with the Everus spinoff, of which $536,000 and $854,000 were recognized in 2025 and 2024, respectively, and the remainder will be recognized in expense over the remaining service period of the applicable awards.

Total stock-based compensation expense (after tax) was $5.9 million, $7.1 million and $5.1 million in 2025, 2024 and 2023, respectively. The Company uses the straight-line amortization method to recognize compensation expense related to RSUs, which only has a service condition. The Company recognizes compensation expense related to PSAs with market-based and performance metrics on a straight-line basis over the requisite service period. As of December 31, 2025, total remaining unrecognized compensation expense related to stock-based compensation was approximately $8.7 million (before income taxes) which will be amortized over a weighted average period of 1.3 years.

Stock awards

Non-employee directors receive shares of common stock in addition to and in lieu of cash payment for directors' fees. There were 51,651 shares with a fair value of $1.1 million, 46,341 shares with a fair value of $850,000 and 50,717 shares with a fair value of $950,000 issued to non-employee directors during the years ended December 31, 2025, 2024 and 2023, respectively.

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Restricted stock units

In February 2025, 2024 and 2023, key employees were granted RSUs under the long-term performance-based incentive plan authorized by the Company's compensation committee. The compensation committee has the authority to select the recipients of awards, determine the type and size of awards, and establish certain terms and conditions of unit award grants. The shares vest over three years, contingent on continued employment. Compensation expense is recognized over the vesting period. Upon vesting, participants receive dividends that accumulate during the vesting period. As previously discussed, adjustments were made to the number of RSUs to preserve the intrinsic value of the awards in connection with the spinoffs of Knife River and Everus and outstanding PSAs in place at the time of the Knife River spinoff were converted to RSUs.

Target grants of RSUs outstanding at December 31, 2025, were as follows:

Grant Date			Performance Period			Target Grant of Shares
February 2024/ June 2024			2024-2026			648,885
February 2025			2025-2027			126,910

A summary of the status of the RSUs for the year ended December 31, 2025, was as follows:

			RSUs
			Number of Shares			Weighted Average Grant-Date Fair Value			*
Nonvested at beginning of period			1,240,517			$	12.56
Granted			126,910			16.83
Forfeited			(49,399)			12.12
Non-vested			1,318,028
Vested shares			(542,233)			12.90
Nonvested at end of period			775,795			$	12.89
* Weighted average grant-date fair values post-separation of Everus reflects incremental fair value related to modifying the awards and the Company's adjusted stock price due to the separation.

Performance share awards

In February 2025, key employees were granted PSAs under the long-term performance-based incentive plan authorized by the Company's compensation committee. The compensation committee has the authority to select the recipients of awards, determine the type and size of awards, and establish certain terms and conditions of award grants. Upon vesting, participants receive dividends that accumulate during the vesting period. Entitlement to performance shares is established by either the market condition or the performance metrics and service condition relative to the designated awards.

Target grants of PSAs outstanding at December 31, 2025, were as follows:

Grant Date			Performance Period			Target Grant of Shares
February 2025			2025-2027			296,128

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Under the market condition for these PSAs, participants could earn from zero to 200 percent of the apportioned target grant of shares based on the Company's total stockholder return relative to that of the selected peer group. Compensation expense is based on the grant-date fair value as determined by Monte Carlo simulation. The blended volatility term structure ranges are comprised of 50 percent historical volatility and 50 percent implied volatility. Risk-free interest rates were based on U.S. Treasury security rates in effect as of the grant date. Assumptions used for initial grants applicable to the market condition for certain PSAs issued in 2025 were:

			2025
Weighted average grant-date fair value			$	17.23
Blended volatility range			26.53% - 27.75%
Risk-free interest rate range			4.40% - 4.58%
Weighted average discounted dividends per share			$	1.30

Under the performance condition for these PSAs, participants could earn from zero to 200 percent of the apportioned target grant of shares. The performance condition was based on the Company's cumulative earnings per share growth. The weighted average grant-date fair value per share for the PSAs applicable to this performance condition issued in 2025 was $16.83.

A summary of the status of the PSAs for the year ended December 31, 2025, was as follows:

			PSAs
			Number of Shares			Weighted Average Grant-Date Fair Value
Nonvested at beginning of period			—			$	—
Granted			296,128			17.03
Forfeited			—			—
Vested shares			—
Nonvested at end of period			296,128			$	17.03

Note 13 - Income Taxes

The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows:

			2025			2024			2023
			(In thousands)
United States			$	210,977		$	198,662		$	340,330
Income before income taxes from continuing operations			$	210,977		$	198,662		$	340,330

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:

			2025			2024			2023
			(In thousands)
Current:
Federal			$	25,971		$	30,412		$	8,271
State			2,522			3,255			3,251
			28,493			33,667			11,522
Deferred:
Income taxes:
Federal			(13,970)			(17,321)			(3,331)
State			1,171			(1,805)			(125)
Investment tax credit - net			3,876			3,048			2,147
			(8,923)			(16,078)			(1,309)
Total income tax expense			$	19,570		$	17,589		$	10,213

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Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:

			2025			2024
			(In thousands)
Deferred tax assets:
Environmental compliance			$	49,750		$	33,730
Pension and postretirement			23,443			25,508
Compensation-related			16,249			15,651
Customer advances			10,590			9,719
Cost recovery mechanisms			10,077			7,402
Legal and environmental contingencies			5,474			5,317
Other			17,989			20,386
Total deferred tax assets			133,572			117,713
Deferred tax liabilities:
Basis differences on property, plant and equipment			451,595			426,493
Pension and postretirement			47,931			48,355
Cost recovery mechanisms			18,109			19,245
Environmental compliance			17,173			17,260
Legal and environmental contingencies			6,399			6,300
Purchased gas adjustment			5,137			20,441
Other			23,695			19,931
Total deferred tax liabilities			570,039			558,025
Valuation allowance			819			1,008
Net deferred income tax liability			$	437,286		$	441,320

As of December 31, 2025 and 2024, the Company had various state income tax net operating loss carryforwards of $819,000 and $1.0 million, respectively, and state income tax credit carryforwards, excluding alternative minimum tax credit carryforwards, of $28.5 million and $31.6 million, respectively. The state income tax credit carryforwards are due to expire between 2027 and 2039. Changes in tax regulations or assumptions regarding current and future taxable income could require additional valuation allowances in the future.

The following table reconciles the change in the net deferred income tax liability from December 31, 2024, to December 31, 2025, to deferred income tax benefit:

			2025
(In thousands)
Change in net deferred income tax liability from the preceding table			$	(4,034)
Effects of rate-regulated accounting			(4,890)
Deferred taxes associated with other comprehensive income			1
Deferred income tax benefit for the period			$	(8,923)

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Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference were as follows:

Year ended December 31,			2025
			Amount			%
U.S. federal statutory tax rate			$	44,305		21.0
State and local income taxes, net of federal income tax effect *			2,917			1.4
Tax credits
Federal renewable energy credit			(19,324)			(9.2)
Other			(1,938)			(0.9)
Nontaxable or nondeductible Items			(265)			(0.1)
Other
Effects of rate-regulated accounting			(5,169)			(2.5)
Other			(956)			(0.4)
Total income tax expense and effective tax rate			$	19,570		9.3
* In 2025, state income taxes in Oregon and Montana made up the majority (greater than 50%) of the tax effect in this category.

Years ended December 31,			2024						2023
			Amount			%			Amount			%
Computed tax at federal statutory rate			$	41,719		21.0			$	71,469		21.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax			4,047			2.0			3,605			1.1
State investment tax credit, net of federal income tax			2,400			1.2			1,545			0.5
Executive compensation			2,111			1.1			564			0.2
Federal renewable energy credit			(16,871)			(8.5)			(15,175)			(4.5)
Excess deferred income tax amortization			(8,121)			(4.1)			(8,383)			(2.5)
State tax rate change			(2,317)			(1.2)			(9)			—
Research and development tax credit			(1,465)			(0.7)			(1,985)			(0.6)
Nonqualified benefit plans			(1,142)			(0.6)			(1,313)			(0.4)
Tax-free debt for equity exchange			—			—			(38,967)			(11.4)
Other			(2,772)			(1.4)			(1,138)			(0.3)
Total income tax expense			$	17,589		8.8			$	10,213		3.1

The Company's effective tax rate for 2025 differs from the U.S. federal statutory rate of 21 percent due primarily to the impact of credits and deductions provided by law and the effects of rate-regulated accounting, primarily the amortizations of excess deferred income taxes and deferred investment tax credits.

Income taxes paid (net of refunds) for the year ended December 31, 2025, was $30.8 million, consisting of $27.7 million in federal income taxes and $3.1 million in state income taxes. Income taxes paid (net of refunds) in Montana of $1.8 million exceeded 5 percent of total income taxes paid (net of refunds).

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state and local jurisdictions. The Company is no longer subject to U.S. federal, non-U.S., state or local income tax examinations by tax authorities for years ending prior to 2021.

Total reserves for uncertain tax positions were not material. The Company recognizes interest and penalties accrued relative to unrecognized tax benefits in income tax expense.

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Note 14 - Business Segment Data

The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business activities due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's CODM, the chief executive officer. The Company's operations are located within the United States.

The Company’s CODM regularly reviews discrete financial information of each reportable segment and uses net income to assess performance of each reportable segment. The CODM uses this information to assess performance and make decisions about resources to be allocated to each reportable segment, including capital and personnel. The information provided to the CODM is prepared at the reportable segment level in quarterly financial packages and on a more summarized basis monthly. Budget and forecast information is also provided to the CODM at the reportable segment level.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states, as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.

The pipeline segment provides natural gas transportation and underground storage services through a FERC regulated pipeline system primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides non-regulated energy-related services, including cathodic protection.

The Other category includes the activities of Centennial Capital, which, through its subsidiary InterSource Insurance Company, insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the self-insured layers of the insured Company's general liability, automobile liability, pollution liability and other coverages. Centennial Capital also owns certain personal property. In addition, the Other category includes certain assets, liabilities and tax adjustments of the holding company primarily associated with corporate functions, as well as the gain on the tax-free exchange of the retained shares in Knife River and costs associated with certain strategic initiatives. Also included are certain general and administrative costs (reflected in operation and maintenance expense) and interest expense, which were previously allocated to Knife River, Everus, Fidelity and the refining business and did not meet the criteria for discontinued operations.

Discontinued operations includes the results of operations for Knife River and Everus and certain associated separation costs, including interest on certain debt facilities repaid in connection with the separations. For the comparative periods below, Everus' operations are only reflected through October 2024 compared to the full year in 2023 and Knife River's operations are only reflected through May 2023. Discontinued operations also includes the supporting activities of Fidelity other than certain general and administrative costs and interest expense as described above.

98 MDU Resources Group, Inc. Form 10-K

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The information below follows the same accounting policies as described in Note 2. Information on the Company's segments as of December 31 and for the years then ended was as follows:

Year ended December 31, 2025			Electric						Natural gas distribution						Pipeline						Other						Consolidated
			(In thousands)
Operating revenues:
External operating revenues			$	437,777					$	1,283,130					$	154,159					$	—					$	1,875,066
Intersegment operating revenues			553						345						74,992						722						76,612
Operation and maintenance:
External operation and maintenance			110,731						240,911						81,619						(238)						433,023
Intersegment operation and maintenance			553						345						133						722						1,753
Purchased natural gas sold:
External purchased natural gas sold			—						671,466						—						—						671,466
Intersegment purchased natural gas sold			—						74,859						—						—						74,859
Electric fuel and purchased power			158,995						—						—						—						158,995
Depreciation and amortization			69,608						104,976						32,124						—						206,708
Taxes, other than income			18,805						81,467						14,225						—						114,497
Other income:
External other income			7,470						15,792						3,488						1,599						28,349
Intersegment other income			—						—						243						4,992						5,235
Interest expense:
External interest expense			31,790						59,587						11,679						4,693						107,749
Intersegment interest expense			—						—						4,992						243						5,235
Income tax expense (benefit)			(9,578)						9,604						19,932						(388)						19,570
Income (loss) from continuing operations			64,896						56,052						68,178						2,281						191,407
Discontinued operations, net of tax			—						—						—						(1,012)						(1,012)
Net income			$	64,896					$	56,052					$	68,178					$	1,269					$	190,395
Capital expenditures (a)			$	422,929					$	298,553					$	59,348					$	—					$	780,830
Assets			$	2,367,067		(b)			$	3,909,046		(b)			$	1,196,959					$	149,134		(c)			$	7,622,206
Property, plant and equipment			$	2,868,379		(b)			$	4,003,754		(b)			$	1,388,691					$	4,148					$	8,264,972
Accumulated depreciation and amortization			$	734,674		(b)			$	1,194,279		(b)			$	373,020					$	2,814					$	2,304,787

(a)Capital expenditures include noncash transactions such as capital expenditure-related accounts payable and AFUDC totaling $(10.8) million.

(b)Includes allocations of common utility property for the Electric and Natural gas distribution segments.

(c)Other includes assets not directly assignable to a business (i.e. cash, cash equivalents and restricted cash, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

MDU Resources Group, Inc. Form 10-K 99

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Year ended December 31, 2024			Electric						Natural gas distribution						Pipeline						Other						Consolidated
			(In thousands)
Operating revenues:
External operating revenues			$	414,406					$	1,200,975					$	142,597					$	—					$	1,757,978
Intersegment operating revenues			72						130						69,222						195						69,619
Operation and maintenance:
External operation and maintenance			94,897						231,087						75,456						13,051						414,491
Intersegment operation and maintenance			72						130						324						195						721
Purchased natural gas sold:
External purchased natural gas sold			—						630,403						—						—						630,403
Intersegment purchased natural gas sold			—						68,898						—						—						68,898
Electric fuel and purchased power			141,148						—						—						—						141,148
Depreciation and amortization			66,524						101,958						29,362						2,234						200,078
Taxes, other than income			17,605						76,042						12,175						394						106,216
Other income:
External other income			8,205						25,509						5,850						1,803						41,367
Intersegment other income			—						—						655						14,798						15,453
Interest expense:
External interest expense			30,058						63,185						10,862						4,242						108,347
Intersegment interest expense			—						—						4,633						10,820						15,453
Income tax expense (benefit)			(2,414)						7,974						17,470						(5,441)						17,589
Income from continuing operations			74,793						46,937						68,042						(8,699)						181,073
Discontinued operations, net of tax			—						—						—						100,035						100,035
Net income			$	74,793					$	46,937					$	68,042					$	91,336					$	281,108
Capital expenditures (a)			$	110,812					$	286,152					$	126,806					$	1,728					$	525,498
Assets			$	1,976,912		(b)			$	3,730,532		(b)			$	1,151,317					$	180,057		(c)			$	7,038,818
Property, plant and equipment			$	2,480,816		(b)			$	3,731,093		(b)			$	1,338,006					$	4,148					$	7,554,063
Accumulated depreciation and amortization			$	716,736		(b)			$	1,139,223		(b)			$	351,045					$	2,767					$	2,209,771

(a)Capital expenditures include noncash transactions such as capital expenditure-related accounts payable and AFUDC totaling $7.1 million.

(b)Includes allocations of common utility property for the Electric and Natural gas distribution segments.

(c)Other includes assets of discontinued operations and assets not directly assignable to a business (i.e. cash, cash equivalents and restricted cash, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

100 MDU Resources Group, Inc. Form 10-K

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Year ended December 31, 2023			Electric						Natural gas distribution						Pipeline						Other						Consolidated
			(In thousands)
Operating revenues:
External operating revenues			$	401,037					$	1,287,236					$	115,079					$	—					$	1,803,352
Intersegment operating revenues			138						301						62,533						119						63,091
Operation and maintenance:
External operation and maintenance			92,521						219,481						70,386						24,693						407,081
Intersegment operation and maintenance			138						301						431						119						989
Purchased natural gas sold:
External purchased natural gas sold			—						742,965						—						—						742,965
Intersegment purchased natural gas sold			—						62,102						—						—						62,102
Electric fuel and purchased power			134,779						—						—						—						134,779
Depreciation and amortization			64,253						95,300						26,811						4,086						190,450
Taxes, other than income			16,695						75,207						10,822						409						103,133
Realized gain on tax-free exchange of the retained shares in Knife River			—						—						—						186,556						186,556
Other income:
External other income			5,815						20,867						3,675						3,097						33,454
Intersegment other income			—						—						217						13,431						13,648
Interest expense:
External interest expense			28,064						57,601						9,428						9,531						104,624
Intersegment interest expense			—						—						3,842						9,806						13,648
Income tax expense (benefit)			(1,019)						6,927						12,409						(8,104)						10,213
Income (loss) from continuing operations			71,559						48,520						47,375						162,663						330,117
Discontinued operations, net of tax			—						—						(457)						85,047						84,590
Net income			$	71,559					$	48,520					$	46,918					$	247,710					$	414,707
Capital expenditures (a)			$	109,805					$	274,836					$	115,903					$	(2,825)					$	497,719
Assets			$	1,955,644		(b)			$	3,532,142		(b)			$	1,045,704					$	1,299,669		(c)			$	7,833,159
Property, plant and equipment			$	2,369,039		(b)			$	3,462,187		(b)			$	1,218,387					$	31,654					$	7,081,267
Accumulated depreciation and amortization			$	660,438		(b)			$	1,068,037		(b)			$	328,010					$	19,890					$	2,076,375

(a)Capital expenditures include noncash transactions such as capital expenditure-related accounts payable and AFUDC totaling $(13.6) million.

(b)Includes allocations of common utility property for the Electric and Natural gas distribution segments.

(c)Other includes assets of discontinued operations and assets not directly assignable to a business (i.e. cash, cash equivalents and restricted cash, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

A reconciliation of reportable segment operating revenues and assets to consolidated operating revenues and assets is as follows:

			2025			2024			2023
						(In thousands)
Operating revenues reconciliation:
Total reportable segment operating revenues			$	1,950,956		$	1,827,402		$	1,866,324
Other revenue			722			195			119
Elimination of intersegment operating revenues			(76,612)			(69,619)			(63,091)
Total consolidated operating revenues			$	1,875,066		$	1,757,978		$	1,803,352
Asset reconciliation:
Total reportable segment assets			$	7,507,105		$	6,892,959		$	6,564,962
Other assets			310,165			525,258			1,847,432
Elimination of intersegment receivables			(195,064)			(379,399)			(579,235)
Total consolidated assets			$	7,622,206		$	7,038,818		$	7,833,159

MDU Resources Group, Inc. Form 10-K 101

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Part II

Note 15 - Employee Benefit Plans

Pension and other postretirement benefit plans

The Company has noncontributory qualified defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.

Prior to 2013, defined benefit pension plan benefits and accruals for all nonunion and certain union plans were frozen and on June 30, 2015, the remaining union plan was frozen. These employees were eligible to receive additional defined contribution plan benefits.

Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees who had attained age 55 with 10 years of continuous service by December 31, 2010, were provided the option to choose between a pre-65 comprehensive medical plan coupled with a Medicare supplement or a specified company funded Retiree Reimbursement Account, regardless of when they retire. All other eligible employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire to be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, will not be eligible for retiree medical benefits.

In 2012, the Company modified health care coverage for certain retirees. Effective January 1, 2013, post-65 coverage was replaced by a fixed-dollar subsidy for retirees and spouses to be used to purchase individual insurance through a healthcare exchange.

Changes in benefit obligation and plan assets and amounts recognized in the Consolidated Balance Sheets at December 31 were as follows:

			Pension Benefits						Other Postretirement Benefits
			2025			2024			2025			2024
Change in benefit obligation:			(In thousands)
Benefit obligation at beginning of year			$	255,350		$	275,586		$	35,675		$	39,590
Service cost			—			—			397			505
Interest cost			13,212			12,799			1,847			1,837
Plan participants' contributions			—			—			384			412
Actuarial loss (gain)			3,080			(11,040)			(355)			(3,420)
Benefits paid			(21,516)			(21,995)			(2,924)			(3,249)
Benefit obligation at end of year			250,126			255,350			35,024			35,675
Change in net plan assets:
Fair value of plan assets at beginning of year			230,626			248,558			78,765			79,234
Actual return on plan assets			19,197			1,152			7,118			2,297
Employer contribution			3,365			2,911			66			71
Plan participants' contributions			—			—			384			412
Benefits paid			(21,516)			(21,995)			(2,924)			(3,249)
Fair value of net plan assets at end of year			231,672			230,626			83,409			78,765
Funded status - (under) over			$	(18,454)		$	(24,724)		$	48,385		$	43,090
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent assets - other			$	203		$	—		$	48,385		$	43,090
Noncurrent liabilities - other			18,657			24,724			—			—
Benefit obligation (liabilities) assets - net amount recognized			$	(18,454)		$	(24,724)		$	48,385		$	43,090
Amounts recognized in accumulated other comprehensive loss:
Actuarial loss (gain)			$	12,814		$	13,228		$	(800)		$	(809)
Prior service credit			—			—			(13)			(37)
Total			$	12,814		$	13,228		$	(813)		$	(846)
Amounts recognized in regulatory assets or liabilities:
Actuarial loss (gain)			$	134,065		$	139,962		$	(3,472)		$	(1,478)
Prior service credit			—			—			(169)			(1,303)
Total			$	134,065		$	139,962		$	(3,641)		$	(2,781)

102 MDU Resources Group, Inc. Form 10-K

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Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from, plan assets. Amounts related to regulated operations are recorded as regulatory assets or liabilities and are expected to be reflected in rates charged to customers over time. For more information on regulatory assets and liabilities, see Note 6.

In 2025, the actuarial loss recognized in the benefit obligation was primarily the result of a decrease in the discount rate. In 2024, the actuarial gain recognized in the benefit obligation was primarily the result of an increase in the discount rate. For more information on the discount rates, see the table below. Unrecognized pension actuarial gains and losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average life expectancy of plan participants for frozen plans. The market-related value of assets is determined using a five-year average of assets.

All but one of the pension plans have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:

			2025			2024
			(In thousands)
Projected benefit obligation			$	250,126		$	255,350
Accumulated benefit obligation			$	250,126		$	255,350
Fair value of plan assets			$	231,672		$	230,626

The components of net periodic benefit cost (credit), other than the service cost component, are included in other income on the Consolidated Statements of Income. Prior service credit is amortized on a straight-line basis over the average remaining service period of active participants. These components related to the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:

			Pension Benefits									Other Postretirement Benefits
			2025			2024			2023			2025			2024			2023
Components of net periodic benefit cost (credit):			(In thousands)
Service cost			$	—		$	—		$	—		$	397		$	505		$	534
Interest cost			13,212			12,799			13,521			1,847			1,837			1,956
Expected return on assets			(14,581)			(16,113)			(17,194)			(5,168)			(5,315)			(5,361)
Amortization of prior service credit			—			—			—			(1,158)			(1,318)			(1,318)
Recognized net actuarial loss (gain)			4,774			4,149			3,093			(320)			(288)			(504)
Net periodic benefit cost (credit), including amount capitalized			3,405			835			(580)			(4,402)			(4,579)			(4,693)
Less amount capitalized			—			—			—			—			—			107
Net periodic benefit cost (credit)			3,405			835			(580)			(4,402)			(4,579)			(4,800)
Other changes in plan assets and benefit obligations recognized in accumulated comprehensive loss:
Net (gain) loss			(14)			401			187			(119)			71			(604)
Amortization of actuarial (loss) gain			(400)			(359)			(292)			82			130			108
Amortization of prior service credit			—			—			—			49			45			78
Total recognized in accumulated other comprehensive loss			(414)			42			(105)			12			246			(418)
Other changes in plan assets and benefit obligations recognized in regulatory assets or liabilities:
Net (gain) loss			(1,523)			3,520			1,826			(2,186)			(472)			(107)
Amortization of actuarial (loss) gain			(4,374)			(3,790)			(2,801)			238			158			304
Amortization of prior service credit			—			—			—			1,109			1,273			1,273
Total recognized in regulatory assets or liabilities			(5,897)			(270)			(975)			(839)			959			1,470
Total recognized in net periodic benefit credit, accumulated other comprehensive loss and regulatory assets or liabilities			$	(2,906)		$	607		$	(1,660)		$	(5,229)		$	(3,374)		$	(3,748)

MDU Resources Group, Inc. Form 10-K 103

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Part II

Weighted average assumptions used to determine benefit obligations at December 31 were as follows:

			Pension Benefits						Other Postretirement Benefits
			2025			2024			2025			2024
Discount rate			5.23		%	5.41		%	5.28		%	5.43		%
Expected return on plan assets			6.50		%	6.50		%	6.00		%	6.00		%

Weighted average assumptions used to determine net periodic benefit cost (credit) for the years ended December 31 were as follows:

			Pension Benefits						Other Postretirement Benefits
			2025			2024			2025			2024
Discount rate			5.41		%	4.84		%	5.43		%	4.85		%
Expected return on plan assets			6.50		%	6.50		%	6.00		%	6.00		%

The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2025, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40 percent to 50 percent equity securities and 50 percent to 60 percent fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 10 percent to 20 percent equity securities and 80 percent to 90 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.

Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:

			2025			2024
Health care trend rate assumed for next year (pre-65/post-65)			9.5%/7.00%			8.5%/6.25%
Health care cost trend rate - ultimate			4.5		%	4.5		%
Year in which ultimate trend rate achieved (pre-65/post-65)			2036/2035			2035/2034

The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of retirement. The Company contributes a flat dollar amount to the monthly premiums which is updated annually on January 1.

The Company expects to contribute to its defined benefit pension plans in 2026 the minimum funding requirement of $3.8 million. The Company expects to contribute approximately $10,000 to its postretirement benefit plans in 2026.

The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies at December 31, 2025, are as follows:

Years			Pension Benefits			Other Postretirement Benefits			Expected Medicare Part D Subsidy
						(In thousands)
2026			$	21,910		$	3,223		$	33
2027			$	21,730		$	3,159		$	26
2028			$	21,390		$	3,079		$	19
2029			$	21,090		$	2,947		$	13
2030			$	20,630		$	2,838		$	10
2031-2035			$	95,250		$	13,410		$	15

104 MDU Resources Group, Inc. Form 10-K

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Outside investment managers manage the Company's pension and postretirement assets. The Company's investment policy with respect to pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of funds in cash equivalents, fixed-income securities and equity securities. The guidelines prohibit investment in commodities and futures contracts, equity private placement, employer securities, leveraged or derivative securities, options, direct real estate investments, precious metals, venture capital and limited partnerships. The guidelines also prohibit short selling and margin transactions. The Company's practice is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The fair value ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The estimated fair values of the Company's pension plans' assets are determined using the market approach.

The carrying value of the pension plans' Level 2 cash equivalents approximates fair value and is determined using observable inputs in active markets or the net asset value of shares held at year end, which is determined using other observable inputs including pricing from outside sources.

The estimated fair value of the pension plans' Level 1 and Level 2 equity securities are based on the closing price reported on the active market on which the individual securities are traded or other known sources including pricing from outside sources. The estimated fair value of the pension plans' Level 1 and Level 2 collective and mutual funds are based on the net asset value of shares held at year end, based on either published market quotations on active markets or other known sources including pricing from outside sources. The estimated fair value of the pension plans' Level 2 corporate and municipal bonds is determined using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, future cash flows and other reference data. The estimated fair value of the pension plans' Level 1 U.S. Government securities are valued based on quoted prices on an active market. The estimated fair value of the pension plans' Level 2 U.S. Government securities are valued mainly using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, to be announced prices, future cash flows and other reference data.

All investments measured at net asset value in the tables that follow are invested in commingled funds, separate accounts or common collective trusts which do not have publicly quoted prices. The fair value of the commingled funds, separate accounts and common collective trusts are determined based on the net asset value of the underlying investments. The fair value of the underlying investments held by the commingled funds, separate accounts and common collective trusts is generally based on quoted prices in active markets.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.

MDU Resources Group, Inc. Form 10-K 105

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The fair value of the Company's pension plans' assets by class were as follows:

			Fair Value Measurements  at December 31, 2025, Using
			Quoted Prices in Active Markets for Identical Assets  (Level 1)			Significant Other Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)			Balance at December 31, 2025
			(In thousands)
Assets:
Cash equivalents			$	—		$	3,993		$	—		$	3,993
Equity securities:
U.S. companies			14			—			—			14
Collective and mutual funds (a)			86,424			78,216			—			164,640
U.S. Government securities			36,744			26,281			—			63,025
Total assets measured at fair value			$	123,182		$	108,490		$	—		$	231,672

(a)Collective and mutual funds invest approximately 35 percent in corporate bonds, 30 percent in U.S. Government securities, 13 percent in common stock of international companies, 12 percent in common stock of large-cap and mid-cap U.S. companies, and 10 percent in other investments.

			Fair Value Measurements  at December 31, 2024, Using
			Quoted Prices in Active Markets for Identical Assets  (Level 1)			Significant Other Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)			Balance at December 31, 2024
			(In thousands)
Assets:
Cash equivalents			$	—		$	4,512		$	—		$	4,512
Equity securities:
U.S. companies			(2)			—			—			(2)
Collective and mutual funds (a)			72,777			93,606			—			166,383
U.S. Government securities			33,616			25,857			—			59,473
Investments measured at net asset value (b)			—			—			—			260
Total assets measured at fair value			$	106,391		$	123,975		$	—		$	230,626

(a)Collective and mutual funds invest approximately 39 percent in corporate bonds, 19 percent in U.S. Government securities, 17 percent in other investments, 15 percent in common stock of international companies, 9 percent in common stock of large-cap and mid-cap U.S. companies, and 1 percent cash and cash equivalents.

(b)In accordance with ASC 820 - Fair Value Measurements, certain investments that were measured at net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the Consolidated Balance Sheets.

The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.

The estimated fair value of the other postretirement benefit plans' Level 2 cash equivalents is valued at the net asset value of shares held at year end, based on published market quotations on active markets, or using other known sources including pricing from outside sources. The estimated fair value of the other postretirement benefit plans' Level 1 and Level 2 equity securities is based on the closing price reported on the active market on which the individual securities are traded or other known sources including pricing from outside sources. The estimated fair value of the other postretirement benefit plans' Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.

106 MDU Resources Group, Inc. Form 10-K

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The fair value of the Company's other postretirement benefit plans' assets by asset class were as follows:

			Fair Value Measurements  at December 31, 2025, Using
			Quoted Prices in Active Markets for Identical Assets  (Level 1)			Significant Other Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)			Balance at December 31, 2025
			(In thousands)
Assets:
Cash equivalents			$	—		$	5,513		$	—		$	5,513
Equity securities:
U.S. companies			2,833			—			—			2,833
Insurance contract (a)			—			74,655			—			74,655
Plan assets (b)			—			—			—			408
Total assets measured at fair value			$	2,833		$	80,168		$	—		$	83,409

(a)The insurance contract invests approximately 37 percent in corporate bonds, 36 percent in U.S. Government securities, 20 percent in common stock of large-cap U.S. companies, 6 percent in common stock of small-cap U.S. companies and 1 percent in other investments.

(b)Deposits held by service providers or claims processors.

			Fair Value Measurements  at December 31, 2024, Using
			Quoted Prices in Active Markets for Identical Assets  (Level 1)			Significant Other Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)			Balance at December 31, 2024
			(In thousands)
Assets:
Cash equivalents			$	—		$	4,373		$	—		$	4,373
Equity securities:
U.S. companies			2,880			—			—			2,880
Insurance contract (a)			—			71,512			—			71,512
Total assets measured at fair value			$	2,880		$	75,885		$	—		$	78,765

(a)The insurance contract invests approximately 41 percent in corporate bonds, 28 percent in U.S. Government securities, 19 percent in common stock of large-cap U.S. companies, 6 percent in common stock of small-cap U.S. companies and 6 percent in other investments.

Nonqualified benefit plans

In addition to the qualified defined benefit pension plans reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified defined benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or, upon death, to their beneficiaries for a 15-year period. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated benefit increases. Vesting for participants not fully vested was retained.

The projected benefit obligation and accumulated benefit obligation for these plans at December 31 were as follows:

			2025			2024
			(In thousands)
Projected benefit obligation			$	49,598		$	52,007
Accumulated benefit obligation			$	49,598		$	52,007

MDU Resources Group, Inc. Form 10-K 107

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The components of net periodic benefit cost are included in other income on the Consolidated Statements of Income. These components related to the Company's nonqualified defined benefit plans for the years ended December 31 were as follows:

			2025			2024			2023
			(In thousands)
Components of net periodic benefit cost:
Interest cost			$	2,588		$	2,568		$	2,740
Recognized net actuarial loss			276			365			273
Net periodic benefit cost			$	2,864		$	2,933		$	3,013

Weighted average assumptions used at December 31 were as follows:

			2025			2024
Benefit obligation discount rate			4.94		%	5.26		%
Benefit obligation rate of compensation increase			N/A			N/A
Net periodic benefit cost discount rate			5.26		%	4.73		%
Net periodic benefit cost rate of compensation increase			N/A			N/A

The amount of future benefit payments for the unfunded, nonqualified defined benefit plans at December 31, 2025, are expected to aggregate as follows:

			2026			2027			2028			2029			2030			2031-2035
			(In thousands)
Nonqualified benefits			$	5,620		$	5,810		$	5,550		$	5,170		$	4,560		$	19,870

In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. In 2020, the plan was frozen to new participants and no new Company contributions will be made to the plan after December 31, 2020. Vesting for participants not fully vested was retained. A new nonqualified defined contribution plan was adopted in 2020, effective January 1, 2021, to replace the plan originally established in 2012 with similar provisions. Expenses incurred under these plans for 2025, 2024 and 2023 were $4.7 million, $4.0 million and $2.7 million, respectively.

The amount of investments that the Company anticipates using to satisfy obligations under these plans at December 31 was as follows:

			2025			2024
			(In thousands)
Investments
Insurance contracts*			$	67,409		$	59,282
Life insurance**			31,290			30,834
Other			9,839			12,879
Total investments			$	108,538		$	102,995

*For more information on the insurance contracts, see Note 8.

**Investments of life insurance are carried on plan participants (payable upon the employee's death).

Defined contribution plans

The Company sponsors a defined contribution plan for eligible employees and the costs incurred under this plan were $19.1 million in 2025, $10.7 million in 2024 and $17.0 million in 2023.

108 MDU Resources Group, Inc. Form 10-K

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Multiemployer plans

The Company contributes to a MEPP under the terms of a collective-bargaining agreement that covers its union-represented employees. The risks of participating in this multiemployer plan is different from single-employer plans in the following aspects:

•Assets contributed to the MEPP by one employer may be used to provide benefits to employees of other participating employers

•If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers

•If the Company chooses to stop participating in its MEPP, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability

The Company's participation in this plan is outlined in the following table. Unless otherwise noted, the most recent Pension Protection Act zone status available in 2025 and 2024 is for the plan's year-end status at December 31, 2024, and December 31, 2023, respectively. The zone status is based on information that the Company received from the plan and is certified by the plan's actuary. Among other factors, a plan in the red zone is generally less than 65 percent funded, a plan in the yellow zone is between 65 percent and 80 percent funded, and a plan in the green zone is at least 80 percent funded.

			EIN/Pension Plan Number			Pension Protection Act Zone Status						FIP/RP Status Pending/Implemented			Contributions									Surcharge Imposed			Expiration Date of Collective Bargaining Agreement
Pension Fund						2025			2024						2025			2024			2023
															(In thousands)
Idaho Plumbers and Pipefitters Pension Plan			826010346-001			Green as of 5/31/2025			Green as of 5/31/2024			No			$	1,553		$	1,434		$	1,690		No			3/31/2027
Total contributions															$	1,553		$	1,434		$	1,690

The Company was listed in the plans' Forms 5500 as providing more than 5 percent of the total contributions for the following plans and plan years:

Pension Fund			Year Contributions to Plan Exceeded More Than 5 Percent of Total Contributions (as of December 31 of the Plan's Year-End)
Idaho Plumbers and Pipefitters Pension Plan			2024 and 2023

MDU Resources Group, Inc. Form 10-K 109

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Note 16 - Jointly Owned Facilities

The consolidated financial statements include the Company's ownership interests in three coal-fired electric generating facilities (Big Stone Station, Coyote Station and Wygen III), two major transmission lines (BSSE and JETx), and a wind turbine farm (Badger Wind Farm). Each owner of the jointly owned facilities is responsible for financing its investment. The Company's share of the jointly owned facilities operating expenses was reflected in the appropriate categories of operating expenses (electric fuel and purchased power; operation and maintenance; and taxes, other than income) in the Consolidated Statements of Income.

In December 2025, the Company completed the acquisition of a 49 percent undivided ownership interest in Badger Wind Farm for approximately $294.0 million, located near Wishek, ND, and placed the asset in service. The purchase was recorded as an asset acquisition to Net, property, plant and equipment on the Company's Consolidated Balance Sheet.

The completed transaction secures 122.5 MW of the project's total 250 MW generation capacity for the Company and follows the NDPSC's Advance Determination of Prudence and Certificate of Public Convenience and Necessity approvals, confirming the project is a prudent, cost-effective investment for customers. The Company previously executed a PPA for 150 MW of output from the project, which included the option to purchase the 49 percent ownership interest. With the closing now complete, the PPA has been reduced to 27.5 MW.

At December 31, the Company's share of the cost of utility plant in service, construction work in progress and related accumulated depreciation for the jointly owned facilities was as follows:

			Ownership Percentage			2025			2024
						(In thousands)
Badger Wind Farm:			49.0		%
Utility plant in service						$	299,823		$	—
CWIP						—			—
Less accumulated depreciation						—			—
						$	299,823		$	—
Big Stone Station:			22.7		%
Utility plant in service						$	157,270		$	155,302
CWIP						1,372			318
Less accumulated depreciation						59,756			55,327
						$	98,886		$	100,293
BSSE:			50.0		%
Utility plant in service						$	111,043		$	111,043
CWIP						—			—
Less accumulated depreciation						12,439			10,359
						$	98,604		$	100,684
Coyote Station:			25.0		%
Utility plant in service						$	163,060		$	160,343
CWIP						110			755
Less accumulated depreciation						117,122			115,133
						$	46,048		$	45,965
JETx:			50.0		%
Utility plant in service						$	—		$	—
CWIP						12,674			6,112
Less accumulated depreciation						—			—
						$	12,674		$	6,112
Wygen III:			25.0		%
Utility plant in service						$	67,664		$	67,851
CWIP						84			97
Less accumulated depreciation						14,351			15,340
						$	53,397		$	52,608

110 MDU Resources Group, Inc. Form 10-K

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Note 17 - Commitments and Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries, which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. Accruals are based on the best information available, but in certain situations management is unable to estimate an amount or range of a reasonably possible loss including, but not limited to when: (1) the damages are unsubstantiated or indeterminate, (2) the proceedings are in the early stages, (3) numerous parties are involved, or (4) the matter involves novel or unsettled legal theories.

At December 31, 2025 and 2024, the Company accrued liabilities which have not been discounted of $26.1 million and $24.1 million, respectively. At December 31, 2025 and 2024, the Company also recorded corresponding receivables of $1.6 million and $24,000, respectively, and regulatory assets of $23.2 million and $22.9 million, respectively, related to the accrued liabilities. The accruals are for contingencies resulting from litigation, regulatory and environmental matters. This includes amounts that have been accrued for matters discussed in Environmental matters within this note. The Company will continue to monitor each matter and adjust accruals as might be warranted based on new information and further developments. In January 2026, the Company received a final order on a regulatory commission complaint for $2.0 million, with $250,000 suspended on the condition that the Company complete additional compliance actions outlined in the order. At December 31, 2025, the Company had $1.75 million included in accrued liabilities for this matter. Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of insurance recoveries, while uncertain, either cannot be estimated or will not have a material effect upon the Company's financial position, results of operations or cash flows. Unless otherwise required by GAAP, legal costs are expensed as they are incurred.

Environmental matters

Manufactured Gas Plant Sites Claims have been made against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors and a similar claim has been made against Montana-Dakota for a site operated by Montana-Dakota and its predecessors. Any accruals related to these claims are reflected in regulatory assets. For more information, see Note 6.

A claim was made against Montana-Dakota for contamination at a manufactured gas plant site in Missoula, Montana. Montana-Dakota and another party agreed to voluntarily investigate and remediate the site and that Montana-Dakota will pay two-thirds of the costs for further investigation and remediation of the site. An environmental assessment was started in 2020 and is still underway. In July 2022, the MTPSC approved Montana-Dakota's application for deferred accounting treatment of costs associated with the investigation and remediation of the site.

In 1997, a claim was made against Cascade for contamination at the Bremerton Gasworks Superfund Site in Bremerton, Washington. The EPA conducted a Targeted Brownfields Assessment of the site which confirmed contamination at the site and in the adjacent Port Washington Narrows. In April 2010, the Washington DOE issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. The preliminary information received through the completion of the data report in August 2020, allowed for the projection of possible costs for a variety of site configurations, remedial measures and potential natural resource damage claims between $13.6 million and $71.5 million. The accrual for remediation costs will be reviewed and adjusted, if necessary, after the completion of the feasibility study. In September 2010, the WUTC approved the petition filed by Cascade regarding deferral of remediation costs, subject to conditions set forth in the order. A significant portion of the costs incurred to date have been recovered by insurance.

MDU Resources Group, Inc. Form 10-K 111

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Part II

A claim was made against Cascade for impacts at a manufactured gas plant site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties. Other PRPs reached an agreed order and work plan with the Washington DOE for completion of a remedial investigation and feasibility study for the site. A feasibility study prepared for one of the PRPs in March 2018 identifies five cleanup action alternatives for the site with estimated costs ranging from $8.0 million to $20.4 million with a selected preferred alternative having an estimated total cost of $9.3 million. The development of the remediation design is underway, with the Pre-Remedial Design Investigation Data Report and Engineering Design Report submitted to Washington Ecology in June 2023 and November 2024, respectively. The remedy construction is expected to commence in 2028 following the approval of the final design. Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. Cascade has recorded an accrual for this site for an amount that is not material.

The Company has received notices from and entered into agreements with certain of its insurance carriers that they will participate in the defense for certain contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, the Company intends to seek recovery of remediation costs through its natural gas rates charged to customers.

Details of the estimates for remedial investigations, feasibility studies and remediation, as well as incurred and accrued costs at these manufactured gas plant sites were as follows:

December 31, 2025			Total Estimated Costs			Total Incurred Costs			Total Accrued Costs
			(In thousands)
Montana-Dakota - Missoula MGP(a)			$	2,042		$	1,232		$	810
Cascade - Bremerton MGP(b)			$	34,730		$	12,772		$	21,958

(a)     Total estimated, incurred and accrued costs for Montana-Dakota's two-thirds share of the ongoing remedial investigation

and remediation of the Missoula site.

(b)    Total estimated, incurred and accrued costs for the ongoing remedial investigation, feasibility study and remediation of

the Bremerton site.

Purchase commitments

The Company has entered into various commitments largely consisting of contracts for natural gas and coal supply; purchased power; natural gas transportation and storage; and information technology. Certain of these contracts are subject to variability in volume and price. The Company's purchase commitments decreased from those reported in the 2024 Annual Report due to a decrease in electric supply contracts as a result of the Company's purchase of a 49 percent undivided ownership interest Badger Wind Farm on December 31, 2025. The commitment terms vary in length, up to 34 years. The commitments under these contracts as of December 31, 2025, were:

			2026			2027			2028			2029			2030			Thereafter
			(In thousands)
Purchase commitments			$	610,505		$	249,341		$	165,751		$	119,053		$	113,147		$	542,117

These commitments were not reflected in the Company's consolidated financial statements. Amounts purchased under various commitments for the years ended December 31, 2025, 2024 and 2023, were $873.5 million, $841.7 million and $1.0 billion, respectively.

Guarantees

The Company and certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At December 31, 2025, the fixed maximum amounts guaranteed under these letters of credit aggregated $3.2 million, all of which have scheduled expiration of the maximum amounts in 2026. There were no amounts outstanding under the previously mentioned letters of credit at December 31, 2025. In the event of default under these letter of credit obligations, the Company or subsidiary guaranteeing the letter of credit would be obligated for reimbursement of payments made under the letter of credit.

In the normal course of business, the Company and its subsidiaries have surety bonds. In the event the Company or its subsidiaries do not fulfill a bonded obligation, the Company or its subsidiaries would be responsible to the surety bond company for completion of the bonded contract or obligation. At December 31, 2025, approximately $13.4 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

112 MDU Resources Group, Inc. Form 10-K

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Leases

Most of the leases the Company enters into are for equipment, buildings, easements and vehicles as part of their ongoing operations. The Company also leases certain equipment to third parties through its utility business. The Company determines if an arrangement contains a lease at inception of a contract and accounts for all leases in accordance with ASC 842 - Leases.

The recognition of leases requires the Company to make estimates and assumptions that affect the lease classification and the assets and liabilities recorded. The accuracy of lease assets and liabilities reported on the Consolidated Financial Statements depends on, among other things, management's estimates of interest rates used to discount the lease assets and liabilities to their present value, as well as the lease terms based on the unique facts and circumstances of each lease.

Lessee accounting The leases the Company has entered into as part of its ongoing operations are considered operating leases and are recognized on the Consolidated Balance Sheets as noncurrent assets - other, current liabilities - other accrued liabilities and noncurrent liabilities - other. The corresponding lease costs are included in operation and maintenance expense on the Consolidated Statements of Income.

Generally, the leases for equipment have a term of five years or less and buildings and easements have a longer term of up to 35 years or more. To date, the Company does not have any residual value guarantee amounts probable of being owed to a lessor, financing leases or material agreements with related parties.

The following tables provide information on the Company's operating leases at and for the years ended December 31:

			2025			2024			2023
			(In thousands)
Lease costs:
Short-term lease cost			$	1,683		$	1,549		$	1,646
Operating lease cost			3,279			3,069			2,871
Variable lease cost			705			819			676
			$	5,667		$	5,437		$	5,193

			2025			2024			2023
			(Dollars in thousands)
Weighted average remaining lease term			19.09 years			12.65 years			15.35 years
Weighted average discount rate			6.17		%	6.08		%	4.88		%
Cash paid for amounts included in the measurement of lease liabilities			$	3,271		$	3,063		$	2,868

The reconciliation of future undiscounted cash flows to operating lease liabilities presented on the Consolidated Balance Sheet at December 31, 2025, was as follows:

			(In thousands)
2026			$	4,104
2027			3,191
2028			2,740
2029			2,657
2030			2,488
Thereafter			45,890
Total			61,070
Less discount			27,311
Total operating lease liabilities*			$	33,759
*The Company's increase in operating lease liabilities in 2025 is primarily due to the Company's 49 percent share of Badger Wind Farm leases.

MDU Resources Group, Inc. Form 10-K 113

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Lessor accounting The Company leases certain equipment to third parties through its utility businesses, which are considered short-term operating leases with terms of less than 12 months. Lease revenue was not material for the years ended December 31, 2025, 2024 and 2023, respectively.

Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary.

Fuel Contract Coyote Station entered into a coal supply agreement with Coyote Creek that provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040. Coal purchased under the coal supply agreement is reflected in Inventories on the Consolidated Balance Sheets and is recovered from customers as a component of electric fuel and purchased power.

The coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations, as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.

At December 31, 2025, the Company's exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, was $23.5 million.

114 MDU Resources Group, Inc. Form 10-K

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.

Evaluation of Disclosure Controls and Procedures

The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of the Company's disclosure controls and other procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and the chief financial officer have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.

Changes in Internal Controls

No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the three months ended December 31, 2025, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Annual Report on Internal Control Over Financial Reporting

The information required by this item is included in this Form 10-K at Item 8 - Management's Report on Internal Control Over Financial Reporting.

Attestation Report of the Registered Public Accounting Firm

The information required by this item is included in this Form 10-K at Item 8 - Report of Independent Registered Public Accounting Firm.

Item 9B. Other Information

During the three months ended December 31, 2025, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

None.

MDU Resources Group, Inc. Form 10-K 115

Part III

Item 10. Directors, Executive Officers, and Corporate Governance

The information required by this item will be included in the sections of the Company's Proxy Statement appearing under the captions "Proposal 1: Election of Directors," "Governance," "Director Compensation," "Our Executive Officers," "Executive Compensation," and "Stockholder Ownership," which is incorporated herein by reference.

Item 11. Executive Compensation

The information required by this item will be included in the section of the Company's Proxy Statement appearing under the caption "Executive Compensation," which is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item will be included in the sections of the Company's Proxy Statement appearing under the captions "Governance," "Proposal 3 - Approval of Amended and Restated LTIP," and "Stockholder Ownership," which is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this item will be included in the section of the Company's Proxy Statement appearing under the caption "Governance," which is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

Information required by this item about aggregate fees billed to the Company by its principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34), will be included in the section of Company's Proxy Statement appearing under the caption "Proposal 4: Ratification of Appointment of Our Independent Registered Public Accounting Firm," which is incorporated herein by reference.

116 MDU Resources Group, Inc. Form 10-K

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Item 15. Exhibits, Financial Statement Schedules

(a) Financial Statements, Financial Statement Schedules and Exhibits

Index to Financial Statements and Financial Statement Schedules

1. Financial Statements
The following consolidated financial statements required under this item are included under Item 8 - Financial Statements and Supplementary Data.			Page
Consolidated Statements of Income for each of the three years in the period ended December 31, 2025			67
Consolidated Statements of Comprehensive Income for each of the three years in the period ended December 31, 2025			68
Consolidated Balance Sheets at December 31, 2025 and 2024			69
Consolidated Statements of Equity for each of the three years in the period ended December 31, 2025			70
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2025			71
Notes to Consolidated Financial Statements			73

2. Financial Statement Schedules
The following financial statement schedules are included in Part IV of this report.			Page
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income for each of the three years in the period ended December 31, 2025			118
Condensed Balance Sheets at December 31, 2025 and 2024			119
Condensed Statements of Cash Flows for each of the three years in the period ended December 31, 2025			120
Notes to Condensed Financial Statements			121

All other schedules have been omitted because they are not applicable or the required information is included elsewhere in the financial statements or related notes.

3. Exhibits 122

MDU Resources Group, Inc. Form 10-K 117

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Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Income and Comprehensive Income

Years ended December 31,			2025			2024			2023
			(In thousands)
Operating revenues			$	—		$	—		$	—
Operating expenses			(137)			4,416			9,668
Operating income (loss)			137			(4,416)			(9,668)
Realized gain on tax-free exchange of the retained shares in Knife River			—			—			186,556
Interest expense			761			642			7,109
Income (loss) before income taxes			(624)			(5,058)			169,779
Income tax benefit			(282)			(2,324)			(4,220)
Equity in earnings of subsidiaries from continuing operations			191,749			183,807			156,118
Income from continuing operations			191,407			181,073			330,117
Equity in (loss)/earnings of subsidiaries from discontinued operations			(72)			140,042			143,181
Discontinued operations, net of tax			(940)			(40,007)			(58,591)
Net income			$	190,395		$	281,108		$	414,707
Comprehensive income			$	190,478		$	282,694		$	414,600

The accompanying notes are an integral part of these condensed financial statements.

118 MDU Resources Group, Inc. Form 10-K

Index

Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Balance Sheets

December 31,			2025			2024
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents			$	310		$	29,361
Receivables, net			911			2,777
Accounts receivable from subsidiaries			33,040			31,955
Taxes receivable			5,325			5,799
Prepayments and other current assets			2,601			3,210
Total current assets			42,187			73,102
Noncurrent assets
Investments			39,938			37,264
Investment in subsidiaries			2,807,285			2,861,311
Deferred income taxes			12,351			13,569
Operating lease right-of-use assets			100			160
Other			3,883			2,874
Total noncurrent assets			2,863,557			2,915,178
Total assets			$	2,905,744		$	2,988,280
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable			$	2,398		$	4,076
Accounts payable to subsidiaries			535			1,077
Notes payable to subsidiaries			—			198,035
Dividends payable			28,614			26,511
Accrued compensation			7,150			7,939
Operating lease liabilities due within one year			63			60
Other accrued liabilities			7,431			7,653
Total current liabilities			46,191			245,351
Noncurrent liabilities:
Long-term debt, net of debt issuance costs			31,765			(536)
Operating lease liabilities			37			100
Other			54,834			52,791
Total noncurrent liabilities			86,636			52,355
Commitments and contingencies
Stockholders' equity:
Common stock Authorized - 500,000,000 shares, $1.00 par value Shares issued - 204,382,821 at December 31, 2025 and 203,934,578 at December 31, 2024			204,383			203,935
Other paid-in capital			1,476,355			1,473,738
Retained earnings			1,108,894			1,029,699
Accumulated other comprehensive loss			(16,715)			(16,798)
Total stockholders' equity			2,772,917			2,690,574
Total liabilities and stockholders' equity			$	2,905,744		$	2,988,280

The accompanying notes are an integral part of these condensed financial statements.

MDU Resources Group, Inc. Form 10-K 119

Index

Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Cash Flows

Years ended December 31,			2025			2024			2023
			(In thousands)
Net cash provided by operating activities of continuing operations			$	115,261		$	482,195		$	282,132
Net cash used in operating activities of discontinued operations			(940)			(40,007)			(58,591)
Net cash provided by operating activities			114,321			442,188			223,541
Investing activities:
Investments in and advances to subsidiaries			(65,000)			(211,000)			(476,000)
Investments			1,314			2,253			7,422
Repayment (issuance) of notes receivable			—			58,000			(58,000)
Net cash used in investing activities of continuing operations			(63,686)			(150,747)			(526,578)
Financing activities:
Issuance of short-term borrowings			—			—			535,000
Repayment of short-term borrowings			—			—			(242,401)
Issuance of long-term debt			32,850			—			443,000
Repayment of long-term debt			—			(58,000)			(385,000)
Debt issuance costs			(705)			(401)			(952)
Costs of issuance of common stock			(79)			(50)			—
Dividends paid			(108,244)			(102,939)			(161,316)
Repurchase of common stock			—			—			(2,270)
Tax withholding on stock-based compensation			(3,508)			(1,729)			(1,471)
Net cash provided by (used in) financing activities of continuing operations			(79,686)			(163,119)			184,590
Net cash provided by (used in) financing activities of discontinued operations			—			(132,000)			132,000
Net cash provided by (used in) financing activities			(79,686)			(295,119)			316,590
Increase (decrease) in cash and cash equivalents			(29,051)			(3,678)			13,553
Cash and cash equivalents - beginning of year			29,361			33,039			19,486
Cash and cash equivalents - end of year			$	310		$	29,361		$	33,039

The accompanying notes are an integral part of these condensed financial statements.

120 MDU Resources Group, Inc. Form 10-K

Index

Part IV

Notes to Condensed Financial Statements

Note 1 - Summary of Significant Accounting Policies

Basis of presentation The condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of Regulation S-X. The information is unconsolidated and is presented for the parent company only, MDU Resources Group, Inc. (the Company) as of and for the years ended December 31, 2025, 2024 and 2023. In Schedule I, investments in subsidiaries are presented under the equity method of accounting where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on the Condensed Balance Sheets. The income from subsidiaries is reported as equity in earnings of subsidiaries on the Condensed Statements of Income. The material cash inflows on the Condensed Statements of Cash Flows are primarily from the dividends and other payments received from its subsidiaries and the proceeds raised from the issuance of debt and equity securities. The consolidated financial statements of the Company reflect certain businesses as discontinued operations. These statements should be read in conjunction with the consolidated financial statements and notes thereto of the Company.

Earnings per common share Please refer to the Consolidated Statements of Income of the registrant for earnings per common share. In addition, see Item 8 - Note 2 for information on the computation of earnings per common share.

Note 2 - Debt

MDU Resources Group, Inc. On December 11, 2025, the Company amended and restated its $200.0 million revolving credit agreement to extend the maturity date from May 31, 2028 to December 11, 2030. This amendment sets forth the terms and conditions under which the syndicate of lenders would make loans to or for the benefit of MDU Resources Group, Inc. These terms and conditions outline the pricing level and applicable facility fee for borrowings or letters of credit under the agreement. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The credit agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments. At December 31, 2025, there was $32.9 million outstanding under the agreement.

At December 31, 2025, the Company had $32.9 million of long-term debt maturities for 2030. For more information on debt, see Item 8 - Note 9.

On May 31, 2023, the Company entered into a $150.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 29, 2024. At December 31, 2023, the Company had no amount outstanding, which remained that way until this agreement matured and subsequently terminated in May 2024.

On May 31, 2023, the Company entered into a $375.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2025. On November 15, 2023, the Company paid down $185.0 million of the term loan agreement. On November 1, 2024, the Company repaid its remaining outstanding balance of $190.0 million and the term loan agreement subsequently terminated. The Company's repayment was funded by the Everus repayment of debt in connection with the separation.

Note 3 - Dividends The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. Cash dividends paid to the Company by subsidiaries were $116.7 million, $418.3 million and $165.5 million for the years ended December 31, 2025, 2024 and 2023, respectively.

MDU Resources Group, Inc. Form 10-K 121

Index

Part IV

Exhibits

Incorporated by Reference

Exhibit Number

Exhibit Description

Filed Herewith

Form

Period Ended

Exhibit

Filing Date

File Number

*2(a)

Separation and Distribution Agreement, dated as of May 30, 2023, by and between Knife River Corporation and MDU Resources Group, Inc.

8-K

2.1

6/1/23

1-03480

*2(b)

Separation and Distribution Agreement, dated as of October 31, 2024, by and between MDU Resources Group, Inc. and Everus Construction Group, Inc.

8-K

2.1

11/1/24

1-03480

3(a)

Amended and Restated Certificate of Incorporation of MDU Resources Group, Inc.

8-K

3.2

5/8/19

1-03480

3(b)

Bylaws of MDU Resources Group, Inc.

8-K

3.1

2/14/25

1-03480

4(a)

MDU Resources Group, Inc. Description of Securities

10-K

12/31/19

4(g)

2/21/20

1-03480

4(b)

Indenture, dated as of December 15, 2003, between MDU Resources Group, Inc. and The Bank of New York, as trustee

S-8

4(f)

1/21/04

333-112035

4(c)

First Supplemental Indenture, dated as of November 17, 2009, between MDU Resources Group, Inc. and the Bank of New York Mellon, as trustee

10-K

12/31/09

4(c)

2/17/10

1-03480

**4(d)

Montana-Dakota Utilities Co. Amended and Restated Credit Agreement, dated December 11, 2025, among Montana-Dakota Utilities Co., various lenders, and Wells Fargo Bank, National Association, as Administrative Agent

X

4(e)

Montana-Dakota Utilities Co. Note Purchase Agreement, dated July 24, 2019, among Montana-Dakota Utilities Co. and various purchasers of the notes

10-Q

9/30/19

4(a)

11/1/19

1-03480

**4(f)

Montana-Dakota Utilities Co. Note Purchase Agreement, dated July 11, 2024

10-Q

6/30/24

4(a)

8/8/24

1-03480

**4(g)

Intermountain Gas Company Note Purchase Agreement, dated July 15, 2025

10-Q

9/30/25

4(a)

11/10/25

1-03480

4(h)

WBI Energy Transmission, Inc. Term Loan Agreement, dated April 1, 2024, among WBI Energy Transmission, Inc., Various Lenders, and U.S. Bank National Association, as Administrative Agent

10-Q

3/31/24

4(a)

5/2/24

1-03480

10(a)

Distribution Agreement, dated August 7, 2025

8-K

1.1

8/7/25

1-03480

10(b)

Form of Master Forward Sale Confirmation

8-K

1.2

8/7/25

1-03480

**10(c)

Amended and Restated Credit Agreement, dated as of December 11, 2025, by and among MDU Resources Group, Inc., U.S. Bank National Association, as administrative agent, and the several lenders party thereto, as lenders

X

**10(d)

364-Day Revolving Credit Agreement, dated as of May 31, 2023, by and among MDU Resources Group, Inc., the financial institutions from time to time party thereto and U.S. Bank National Association

8-K

10.6

6/1/23

1-03480

**10(e)

Term Loan Agreement, dated as of May 31, 2023, by and among MDU Resources Group, Inc., the lenders from time to time party thereto and U.S. Bank National Association.

8-K

10.7

6/1/23

1-03480

+10(f)

MDU Resources Group, Inc. Supplemental Income Security Plan, as amended and restated May 10, 2017

10-Q

6/30/17

10(d)

8/4/17

1-03480

+10(g)

MDU Resources Group, Inc. Director Compensation Policy, as amended February 19, 2026

X

+10(h)

Deferred Compensation Plan for Directors, as amended May 15, 2008

10-Q

6/30/08

10(a)

8/7/08

1-03480

122 MDU Resources Group, Inc. Form 10-K

Index

Part IV

Incorporated by Reference

Exhibit Number

Exhibit Description

Filed Herewith

Form

Period Ended

Exhibit

Filing Date

File Number

+10(i)

MDU Resources Group, Inc. Long-Term Performance-Based Incentive Plan, as amended and restated May 14, 2025

8-K

10.1

5/15/25

1-03480

+10(j)

MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended February 13, 2025

10-K

12/31/24

10(n)

2/20/25

1-03480

+10(k)

Form of Performance Share Award Agreement (Absolute) under the Long-Term Performance-Based Incentive Plan, as amended

X

+10(l)

Form of Performance Share Award Agreement (rTSR) under the Long-Term Performance-Based Incentive Plan, as amended

X

+10(m)

Form of Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended

X

+10(n)

Form of Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 16, 2023

10-K

12/31/22

10(m)

2/24/23

1-03480

+10(o)

Form of MDU Resources Group, Inc. Indemnification Agreement for Section 16 Officers and Directors, dated May 15, 2014

8-K

10.1

5/15/14

1-03480

+10(p)

Form of Amendment No. 1 to Indemnification Agreement, dated May 15, 2014

8-K

10.2

5/15/14

1-03480

+10(q)

MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as amended and restated November 12, 2020

10-K

12/31/20

10(r)

2/19/21

1-03480

+10(r)

MDU Resources Group, Inc. Deferred Compensation Plan Adoption Agreement, as amended July 16, 2024

X

+10(s)

MDU Resources Group, Inc. Deferred Compensation Plan Document, dated November 12, 2020

8-K

10.2

11/12/20

1-03480

+10(t)

MDU Resources Group, Inc. Change in Control Severance Plan

8-K

10.1

2/21/24

1-03480

**10(u)

Second Amended and Restated Note Purchase and Private Shelf Agreement, dated as of December 22, 2022, by and among WBI Energy Transmission, Inc., PGIM, Inc., and the other purchasers named therein

8-K

10.1

1/16/26

1-03480

**10(v)

Amendment No. 1, dated as of January 16, 2026, to Second Amended and Restated Note Purchase and Private Shelf Agreement, dated as of December 22, 2022, by and among WBI Energy Transmission, Inc., PGIM, Inc., and the other purchasers named therein

8-K

10.2

1/16/26

1-03480

10(w)

Forward Sale Agreement between MDU Resources Group, Inc. and Wells Fargo Bank, National Association, dated December 3, 2025

8-K

10.1

12/5/25

1-03480

10(x)

Forward Sale Agreement between MDU Resources Group, Inc. and Bank of America, N.A., dated December 3, 2025

8-K

10.2

12/5/25

1-03480

10(y)

Forward Sale Agreement between MDU Resources Group, Inc. and JPMorgan Chase Bank, National Association, New York Branch, dated December 3, 2025

8-K

10.3

12/5/25

1-03480

10(z)

Forward Sale Agreement between MDU Resources Group, Inc. and Wells Fargo Bank, National Association, dated December 23, 2025

8-K

10.1

12/29/25

1-03480

10(aa)

Forward Sale Agreement between MDU Resources Group, Inc. and Bank of America, N.A., dated December 23, 2025

8-K

10.2

12/29/25

1-03480

MDU Resources Group, Inc. Form 10-K 123

Index

Part IV

Incorporated by Reference

Exhibit Number

Exhibit Description

Filed Herewith

Form

Period Ended

Exhibit

Filing Date

File Number

10(bb)

Forward Sale Agreement between MDU Resources Group, Inc. and JPMorgan Chase Bank, National Association, New York Branch, dated December 23, 2025

8-K

10.3

12/29/25

1-03480

**10(cc)

Amended and Restated Credit Agreement, dated as of December 11, 2025, by and among MDU Resources Group, Inc., U.S. Bank National Association, as administrative agent, and the several lenders party thereto, as lenders.

8-K

10.1

12/12/25

1-03480

**10(dd)

Badger Wind Purchase and Sale Agreement between Badger Wind, LLC, and Montana-Dakota Utilities Co., dated February 13, 2025.

8-K

10.1

2/14/25

1-03480

19

Insider Trading Policy

X

21

Subsidiaries of MDU Resources Group, Inc.

X

23

Consent of Independent Registered Public Accounting Firm

X

31(a)

Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

X

31(b)

Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

X

***32

Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

X

+97

Incentive Compensation Recovery Policy

10-K

12/31/23

97

2/22/24

1-03480

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Certain exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally to the SEC a copy of any omitted exhibits or schedules upon request; provided that the Company may request confidential treatment pursuant to Rule 24b-2 of the Exchange Act.

** Schedules and exhibits to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished as a supplement to the SEC upon request.

*** Furnished herewith.

+ Management contract, compensatory plan, or arrangement.

MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

Item 16. Form 10-K Summary

None.

124 MDU Resources Group, Inc. Form 10-K

Index

Part IV

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

						MDU Resources Group, Inc.
Date:			February 20, 2026			By:			/s/ Nicole A. Kivisto
									Nicole A. Kivisto
									(President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the date indicated.

Signature			Title			Date
/s/ Nicole A. Kivisto			President and Chief Executive Officer			February 20, 2026
Nicole A. Kivisto
(President and Chief Executive Officer)
/s/ Jason L. Vollmer			Chief Financial Officer			February 20, 2026
Jason L. Vollmer
(Chief Financial Officer)
/s/ Stephanie A. Sievert			Chief Accounting and Regulatory Affairs Officer			February 20, 2026
Stephanie A. Sievert
(Chief Accounting and Regulatory Affairs Officer)
/s/ Darrel T. Anderson			Director			February 20, 2026
Darrel T. Anderson
(Chair of the Board)
/s/ Vernon A. Dosch			Director			February 20, 2026
Vernon A. Dosch
/s/ Marian M. Durkin			Director			February 20, 2026
Marian M. Durkin
/s/ Douglas W. Jaeger			Director			February 20, 2026
Douglas W. Jaeger
/s/ Dennis W. Johnson			Director			February 20, 2026
Dennis W. Johnson
/s/ Charles M. Kelley			Director			February 20, 2026
Charles M. Kelley
/s/ Tammy J. Miller			Director			February 20, 2026
Tammy J. Miller
/s/ Priti R. Patel			Director			February 20, 2026
Priti R. Patel

MDU Resources Group, Inc. Form 10-K 125

FAQ

What is MDU (MDU) describing in this Form 10-K filing?

MDU’s Form 10-K outlines its operations as a pure-play regulated energy delivery company with electric, natural gas distribution and pipeline segments. It explains business structure, customer base, regulation, environmental obligations and the main economic and operational risks facing future financial performance.

How has MDU (MDU) changed its business portfolio recently?

MDU completed the separation of Knife River on May 31, 2023 and Everus on October 31, 2024, turning both into independent public companies. The remaining business is focused on regulated electricity, natural gas distribution and FERC-regulated pipeline and storage services across the northern and western United States.

What are the main operating segments for MDU (MDU)?

As of December 31, 2025, MDU reports three segments: electric (Montana-Dakota), natural gas distribution (Montana-Dakota, Cascade, Intermountain) and pipeline (WBI Energy). Each segment is regulated by state commissions and/or FERC and contributes distinct revenue streams, infrastructure needs and regulatory frameworks.

How large is MDU’s customer base in its utility businesses?

The electric segment served 146,550 retail customers in 2025, while natural gas distribution served 1,082,329 customers across eight states. These include residential, commercial and industrial classes, with revenues highly influenced by weather, efficiency trends and state-specific mechanisms like decoupling and cost trackers.

What environmental and climate-related issues does MDU (MDU) highlight?

MDU notes extensive environmental regulation over air, water, waste and coal ash, plus emerging state GHG programs in Washington and Oregon. It discusses climate and severe weather risks, wildfire liability, and capital needs for emissions compliance, RNG infrastructure and historic manufactured gas plant remediation activities.

What are key financial and regulatory risks for MDU (MDU)?

Key risks include regulatory lag, prudence reviews, potential stranded costs from early retirements, rising fuel and environmental costs, capital market access, insurance availability, and cost inflation. The company also cites planning risk for long-lived assets and dependence on favorable treatment of trackers and riders in multiple jurisdictions.

How does MDU’s pipeline business contribute to the company?

Through WBI Energy Transmission, MDU operates over 3,800 miles of natural gas transmission and storage lines, plus 350 Bcf of certificated storage capacity. About 94% of segment revenue is FERC-regulated pipeline service, with the balance from non-regulated cathodic protection services in the Rocky Mountain and northern Great Plains regions.