MDU Resources Q3 2026 net income falls to $14.1M
MDU revised its long-term payout target to 55% to 65% of earnings and reached a final investment decision on Bakken East.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Form Type
10-Q
MDU Resources Group reported third-quarter 2026 operating revenues of $347.746 million, compared with $315.036 million a year earlier, while net income was $14.086 million versus $18.311 million. Electric segment earnings increased, but natural gas distribution and pipeline results were lower. The company cited higher operation and maintenance and interest costs, lower returns on benefit-plan investments, and a $2.1 million after-tax loss from discontinuing development of the Knott Landfill renewable natural gas project.
For the first nine months, operating cash flow was $347.607 million versus $392.793 million, and operating revenue was $1,329.026 million versus $1,341.055 million. On September 30, 2026, MDU reached a positive final investment decision to proceed with Bakken East; it reclassified 2026 preliminary investigation costs and $11.0 million incurred in prior fiscal years to construction work in progress. In August, it revised its long-term dividend payout target to 55% to 65% of earnings, from 60% to 70% of regulated energy delivery earnings.
1 point · 0 major0 major · 2 points
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointThird-quarter revenue was $347.746 million, versus $315.036 million.
Negative
- Moderate pointThird-quarter net income was $14.086 million, versus $18.311 million.
- Moderate pointNine-month operating cash flow was $347.607 million, versus $392.793 million.
Filing Explained
The stated three hundred ten million dollars is additional share-sale capacity, not a promise to issue that amount.
At
Its at-the-market program allows gradual sales of new shares at prevailing prices; the company reports up to
Key Figures
Third-quarter operating revenues: $347.746 million
Third-quarter net income: $14.086 million
Diluted earnings per share: $0.07 per share
+4 more
7 metrics
Third-quarter operating revenues
$347.746 million
Three months ended September 30, 2026; $315.036 million in 2025
Third-quarter net income
$14.086 million
Three months ended September 30, 2026; $18.311 million in 2025
Diluted earnings per share
$0.07 per share
Three months ended September 30, 2026; $0.09 per share in 2025
Operating cash flow
$347.607 million
Nine months ended September 30, 2026; $392.793 million in 2025
Operating revenues
$1,329.026 million
Nine months ended September 30, 2026; $1,341.055 million in 2025
Dividends declared per common share
$0.145 per share
Three months ended September 30, 2026; $0.140 per share in 2025
Bakken East pipeline capacity
1.4 billion cubic feet per day
Defined project capacity
Key Terms
Construction work in progress, At-the-market offering program, Final investment decision, Variable interest entity, +1 more
5 terms
Construction work in progress financial
"CWIP | Construction work in progress, costs associated with the construction"
At-the-market offering program financial
"At-the-market offering program"
An at-the-market offering program lets a company sell newly issued shares directly into the open market at current trading prices through a broker, rather than issuing a large block of stock all at once. It matters to investors because it provides the company a flexible way to raise cash over time, which can dilute existing shares gradually and affect earnings per share and stock price depending on how much and when shares are sold—think of it as a faucet the company can open or close to add supply to the market.
Final investment decision technical
"reached a positive final investment decision to proceed with Bakken East"
A final investment decision is the point at which a person or organization chooses to move forward with a particular project or purchase after reviewing all the necessary information and options. It is like deciding to buy a house after considering all the costs, benefits, and alternatives. This decision is important because it determines whether and when the investment will be made, impacting future financial plans and outcomes.
Variable interest entity financial
"Coyote Creek is a VIE"
A variable interest entity (VIE) is a company structure where one party controls another company’s operations and economic outcomes through contracts or special arrangements instead of owning a majority of its voting shares. For investors, VIEs matter because the controlling party’s financial results, debts and risks can appear in the controller’s reports even though ownership looks separate, so understanding VIEs helps assess true exposure, governance limits and transparency—like spotting a puppet controlled by strings rather than direct ownership.
Allowance for funds used during construction financial
"AFUDC | Allowance for funds used during construction"
Allowance for funds used during construction (AFUDC) is the accounting practice of adding the cost of borrowing money and using company funds while building long-term assets to the value of that asset instead of treating it as an immediate expense. For investors, AFUDC matters because it boosts reported profits and increases the company’s asset base today while deferring financing costs to future periods, similar to adding construction loan interest to the price of a house under renovation.
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
How much revenue and net income did MDU report in Q3 2026?
For the three months ended September 30, 2026, MDU reported operating revenues of $347.746 million, compared with $315.036 million a year earlier, and net income of $14.086 million, compared with $18.311 million.
Why did MDU's third-quarter net income decline?
MDU cited higher operation and maintenance and interest expense and lower returns on nonqualified benefit plan investments. Natural gas distribution also recorded a $2.1 million after-tax loss after the decision to discontinue development of the Knott Landfill renewable natural gas project; electric segment earnings increased.
What is MDU's revised dividend payout target?
In August 2026, MDU revised its long-term dividend payout target to 55% to 65% of earnings, from 60% to 70% of regulated energy delivery earnings. The company said the revised range is intended to provide flexibility to fund its capital investment program, reduce future equity needs and support long-term growth.
What is the Bakken East project and what decision did MDU make?
Bakken East is an approximately 350-mile pipeline intended to transport natural gas from North Dakota's Bakken region to eastern North Dakota, with capacity of 1.4 billion cubic feet per day. MDU reached a positive final investment decision to proceed on September 30, 2026.
AI-generated analysis. How Rhea-AI works. Not financial advice.
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended September 30, 2026
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
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
(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 | ||||||
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.
☒ | 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ .
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of October 29, 2026: 213,407,857 shares.
1
| Index | |||||
| Page | |||||
Definitions | 3 | ||||
Introduction | 5 | ||||
Part I -- Financial Information | |||||
Item 1. Financial Statements | 6 | ||||
Consolidated Statements of Income -- Three and Nine Months Ended September 30, 2026 and 2025 | 6 | ||||
Consolidated Statements of Comprehensive Income -- Three and Nine Months Ended September 30, 2026 and 2025 | 7 | ||||
Consolidated Balance Sheets -- September 30, 2026 and 2025, and December 31, 2025 | 8 | ||||
Consolidated Statements of Equity -- Nine Months Ended September 30, 2026 and 2025 | 9 | ||||
Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2026 and 2025 | 11 | ||||
Condensed Notes to Consolidated Financial Statements | 12 | ||||
1. Basis of presentation | 12 | ||||
2. New accounting standards | 13 | ||||
3. Discontinued operations | 13 | ||||
4. Seasonality of operations | 14 | ||||
5. Receivables and allowance for expected credit losses | 14 | ||||
6. Inventories and natural gas in storage | 15 | ||||
7. Earnings per share | 16 | ||||
8. Equity | 16 | ||||
9. Revenue from contracts with customers | 17 | ||||
10. Regulatory matters | 20 | ||||
11. Environmental allowances and obligations | 22 | ||||
12. Fair value measurements | 23 | ||||
13. Debt | 25 | ||||
14. Business segment data | 27 | ||||
15. Employee benefit plans | 31 | ||||
16. Commitments and contingencies | 32 | ||||
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | 34 | ||||
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 51 | ||||
Item 4. Controls and Procedures | 51 | ||||
Part II -- Other Information | |||||
Item 1. Legal Proceedings | 52 | ||||
Item 1A. Risk Factors | 52 | ||||
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 53 | ||||
Item 5. Other Information | 53 | ||||
Item 6. Exhibits | 53 | ||||
Exhibits Index | 54 | ||||
Signatures | 55 | ||||
2
Index
Definitions
The following abbreviations and acronyms used in this Form 10-Q are defined below:
| Abbreviation or Acronym | |||||
2025 Annual Report | Company's Annual Report on Form 10-K for the year ended December 31, 2025 | ||||
| AFUDC | Allowance for funds used during construction | ||||
| Applied Digital | Applied Digital Corporation | ||||
| 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) | ||||
| Bakken East | Bakken East Pipeline project, comprising an approximately 350-mile pipeline to transport natural gas from the Bakken region of North Dakota to eastern North Dakota with a capacity of 1.4 billion cubic feet per day, plus additional pipeline laterals | ||||
Big Stone Station | 475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership) | ||||
Binding Open Season | A formal bidding procedure used by pipelines to determine the level of interest of existing and potential shippers for new or additional firm transportation service | ||||
| 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 | ||||
| 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) | ||||
CPP | Climate Protection Program | ||||
| 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 | ||||
| dk | Decatherm | ||||
| DOE | United States Department of Energy | ||||
EDA | Equity Distribution Agreement | ||||
| EPA | United States Environmental Protection Agency | ||||
| 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 | ||||
| FSA | Forward sale agreement | ||||
| GAAP | Accounting principles generally accepted in the United States of America | ||||
| GHG | Greenhouse gas | ||||
| GRIP | Grid Resilience and Innovative Partnership program established under the Infrastructure Investment and Jobs Act | ||||
3
Index
| 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 | ||||
| HPC | High performance computing | ||||
| Intermountain | Intermountain Gas Company, an indirect wholly-owned subsidiary of MDU Energy Capital | ||||
| JETx | 345-kV transmission line from Jamestown, North Dakota to Ellendale, North Dakota (50 percent ownership) | ||||
| kWh | Kilowatt-hour | ||||
| kV | Kilovolt | ||||
| 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 | ||||
| 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 | ||||
| Montana-Dakota | Montana-Dakota Utilities Co., a direct wholly-owned subsidiary of MDU Energy Capital | ||||
| MTDEQ | Montana Department of Environmental Quality | ||||
| MW | Megawatt | ||||
| NDDEQ | North Dakota Department of Environmental Quality | ||||
| NDPSC | North Dakota Public Service Commission | ||||
| NERC | North American Electric Reliability Corporation | ||||
Ninth Circuit | United States Court of Appeals for the Ninth Circuit | ||||
NPA | Note Purchase Agreement | ||||
OBBBA | One Big Beautiful Bill Act | ||||
| ODEQ | Oregon Department of Environmental Quality | ||||
OEQC | Oregon Environmental Quality Commission | ||||
| PHMSA | Pipeline and Hazardous Materials Safety Administration | ||||
Precedent Agreement | An agreement between a pipeline company and a potential customer to enter into a firm transportation service agreement once specified events, known as conditions precedent, are met within a defined timeframe | ||||
| RNG | Renewable natural gas | ||||
| SBCC | State Building Code Council | ||||
| SDPUC | South Dakota Public Utilities Commission | ||||
SOFR | Secured Overnight Financing Rate | ||||
| SEC | United States Securities and Exchange Commission | ||||
| TSA | In connection with the separation of Everus, the Company and Everus entered into a Transition Services Agreement whereby each party provided certain post-separation services on a transitional basis | ||||
| VIE | Variable interest entity | ||||
| 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 | ||||
4
Index
Introduction
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. Its principal executive offices are located at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.
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.
The Company is 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 CODM.
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.
For more information on the Company's business segments, see Note 14 of the Condensed Notes to Consolidated Financial Statements.
5
Index
Part I -- Financial Information
Item 1. Financial Statements
MDU Resources Group, Inc. | ||||||||||||||
| Consolidated Statements of Income | ||||||||||||||
| (Unaudited) | ||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands, except per share amounts) | ||||||||||||||
| Operating revenues | $ | $ | $ | $ | ||||||||||
| Operating expenses: | ||||||||||||||
| Purchased natural gas sold | ||||||||||||||
| Electric fuel and purchased power | ||||||||||||||
| Operation and maintenance | ||||||||||||||
| Depreciation and amortization | ||||||||||||||
| Taxes, other than income | ||||||||||||||
| Total operating expenses | ||||||||||||||
| Operating income | ||||||||||||||
| Other income | ||||||||||||||
| Interest expense | ||||||||||||||
| Income before income taxes | ||||||||||||||
| Income taxes | ||||||||||||||
| Income from continuing operations | ||||||||||||||
| Discontinued operations, net of tax | ( | ( | ||||||||||||
| Net income | $ | $ | $ | $ | ||||||||||
| Earnings per share - basic: | ||||||||||||||
| Income from continuing operations | $ | $ | $ | $ | ||||||||||
| Discontinued operations, net of tax | ||||||||||||||
| Earnings per share - basic | $ | $ | $ | $ | ||||||||||
| Earnings per share - diluted: | ||||||||||||||
| Income from continuing operations | $ | $ | $ | $ | ||||||||||
| Discontinued operations, net of tax | ||||||||||||||
| Earnings per share - diluted | $ | $ | $ | $ | ||||||||||
| Weighted average common shares outstanding - basic | ||||||||||||||
| Weighted average common shares outstanding - diluted | ||||||||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
6
Index
| MDU Resources Group, Inc. | |||||||||||||||||
| Consolidated Statements of Comprehensive Income | |||||||||||||||||
| (Unaudited) | |||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| (In thousands) | |||||||||||||||||
| Net income | $ | $ | $ | $ | |||||||||||||
| Other comprehensive income: | |||||||||||||||||
| Postretirement liability adjustment: | |||||||||||||||||
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $ | |||||||||||||||||
Net unrealized (loss) gain on available-for-sale investments: | |||||||||||||||||
Net unrealized (loss) gain on available-for-sale investments arising during the period, net of tax of $( | ( | ( | ( | ||||||||||||||
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $ | |||||||||||||||||
| Net unrealized (loss) gain on available-for-sale investments | ( | ( | |||||||||||||||
| Other comprehensive income | |||||||||||||||||
| Comprehensive income attributable to common stockholders | $ | $ | $ | $ | |||||||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
7
Index
| MDU Resources Group, Inc. | |||||||||||
| Consolidated Balance Sheets | |||||||||||
| (Unaudited) | |||||||||||
| September 30, 2026 | September 30, 2025 | December 31, 2025 | |||||||||
| Assets | (In thousands, except shares and per share amounts) | ||||||||||
| Current assets: | |||||||||||
| Cash, cash equivalents and restricted cash | $ | $ | $ | ||||||||
| Receivables, net | |||||||||||
| Current regulatory assets | |||||||||||
| Inventories | |||||||||||
| Current environmental allowances | |||||||||||
| Prepayments and other current assets | |||||||||||
| Total current assets | |||||||||||
| Noncurrent assets: | |||||||||||
| Property, plant and equipment | |||||||||||
| Less accumulated depreciation and amortization | |||||||||||
| Net property, plant and equipment | |||||||||||
| Goodwill | |||||||||||
| Regulatory assets | |||||||||||
| Investments | |||||||||||
| Environmental allowances | |||||||||||
| Other | |||||||||||
| Total noncurrent assets | |||||||||||
| Total assets | $ | $ | $ | ||||||||
| Liabilities and Stockholders' Equity | |||||||||||
| Current liabilities: | |||||||||||
| Long-term debt due within one year | $ | $ | $ | ||||||||
| Accounts payable | |||||||||||
| Regulatory liabilities due within one year | |||||||||||
| Taxes payable | |||||||||||
| Dividends payable | |||||||||||
| Accrued compensation | |||||||||||
| Current environmental obligations | |||||||||||
| Other accrued liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Noncurrent liabilities: | |||||||||||
| Long-term debt | |||||||||||
| Deferred income taxes | |||||||||||
| Regulatory liabilities | |||||||||||
| Asset retirement obligations | |||||||||||
| Environmental obligations | |||||||||||
| Other | |||||||||||
| Total noncurrent liabilities | |||||||||||
| Commitments and contingencies | |||||||||||
Stockholders' equity: | |||||||||||
Common stock Authorized - Shares issued - September 30, 2025 and | |||||||||||
| Other paid-in capital | |||||||||||
| Retained earnings | |||||||||||
| Accumulated other comprehensive loss | ( | ( | ( | ||||||||
| Total stockholders' equity | |||||||||||
| Total liabilities and stockholders' equity | $ | $ | $ | ||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
8
Index
| MDU Resources Group, Inc. | ||||||||||||||||||||
| Consolidated Statements of Equity | ||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||
| Other Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | ||||||||||||||||||
| Common Stock | ||||||||||||||||||||
| Shares | Amount | Total | ||||||||||||||||||
| (In thousands, except shares) | ||||||||||||||||||||
At December 31, 2025 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
| Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
Issuance of common stock, net | — | — | ||||||||||||||||||
| Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings | ( | — | — | ( | ||||||||||||||||
| At March 31, 2026 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
| Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
| Issuance of common stock, net | — | — | ||||||||||||||||||
| At June 30, 2026 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
| Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
| Issuance of common stock, net | — | — | ||||||||||||||||||
| At September 30, 2026 | $ | $ | $ | $ | ( | $ | ||||||||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
9
Index
| MDU Resources Group, Inc. | ||||||||||||||||||||
| Consolidated Statements of Equity | ||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||
| Other Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | ||||||||||||||||||
| Common Stock | ||||||||||||||||||||
| Shares | Amount | Total | ||||||||||||||||||
| (In thousands, except shares) | ||||||||||||||||||||
At December 31, 2024 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
| Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
| Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings | ( | — | — | ( | ||||||||||||||||
| At March 31, 2025 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
| Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
| At June 30, 2025 | $ | $ | $ | $ | ( | $ | ||||||||||||||
| Net income | — | — | — | — | ||||||||||||||||
Other comprehensive income | — | — | — | — | ||||||||||||||||
| Dividends declared on common stock | — | — | — | ( | — | ( | ||||||||||||||
| Stock-based compensation | — | — | — | — | ||||||||||||||||
| Costs of issuance of common stock | — | — | ( | — | — | ( | ||||||||||||||
| At September 30, 2025 | $ | $ | $ | $ | ( | $ | ||||||||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
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Index
| MDU Resources Group, Inc. | |||||||||||
| Consolidated Statements of Cash Flows | |||||||||||
| (Unaudited) | |||||||||||
| Nine Months Ended | |||||||||||
| September 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Operating activities: | |||||||||||
| Net income | $ | $ | |||||||||
| Income (loss) from discontinued operations, net of tax | ( | ||||||||||
| Income from continuing operations | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization | |||||||||||
| Deferred income taxes | ( | ||||||||||
| Provision for credit losses | |||||||||||
| Amortization of debt issuance costs | |||||||||||
| Employee stock-based compensation costs | |||||||||||
| Pension and postretirement benefit plan net periodic benefit cost (credit) | ( | ||||||||||
| Unrealized gains on investments | ( | ( | |||||||||
| Changes in current assets and liabilities, net of acquisitions: | |||||||||||
| Receivables | |||||||||||
| Inventories | ( | ( | |||||||||
| Other current assets | ( | ||||||||||
| Accounts payable | ( | ( | |||||||||
| Other current liabilities | |||||||||||
| Pension and postretirement benefit plan contributions | ( | ( | |||||||||
| Other noncurrent changes | ( | ( | |||||||||
| Net cash provided by continuing operations | |||||||||||
| Net cash provided by (used in) discontinued operations | ( | ||||||||||
| Net cash provided by operating activities | |||||||||||
| Investing activities: | |||||||||||
| Capital expenditures | ( | ( | |||||||||
| Cost of removal, net | ( | ( | |||||||||
Purchase of investment securities | ( | ( | |||||||||
Proceeds from investment securities | |||||||||||
| Net cash used in investing activities | ( | ( | |||||||||
| Financing activities: | |||||||||||
| Issuance of long-term debt | |||||||||||
| Repayment of long-term debt | ( | ( | |||||||||
| Debt issuance costs | ( | ( | |||||||||
Issuance of common stock, net | ( | ||||||||||
| Dividends paid | ( | ( | |||||||||
| Tax withholding on stock-based compensation | ( | ( | |||||||||
| Net cash used in financing activities | ( | ( | |||||||||
| (Decrease) increase in cash, cash equivalents and restricted cash | ( | ||||||||||
| Cash, cash equivalents and restricted cash - beginning of year | |||||||||||
Cash, cash equivalents and restricted cash - end of period | $ | $ | |||||||||
Supplemental cash flow information: | |||||||||||
Cash expenditures during the year for: | |||||||||||
Interest, net* | $ | $ | |||||||||
| Income taxes paid, net | $ | $ | |||||||||
Noncash investing and financing transactions: | |||||||||||
Property, plant and equipment additions in accounts payable | $ | $ | |||||||||
Right-of-use assets obtained in exchange for new operating lease liabilities | $ | $ | |||||||||
*AFUDC - borrowed was $ | |||||||||||
The accompanying condensed notes are an integral part of these consolidated financial statements.
11
Index
MDU Resources Group, Inc.
Condensed Notes to Consolidated
Financial Statements
September 30, 2026 and 2025
(Unaudited)
Note 1 - Basis of presentation
The accompanying consolidated interim financial statements were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2025 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.
On September 30, 2026, the Company reached a positive final investment decision to proceed with Bakken East. As a result, preliminary investigation costs incurred in 2026 prior to the final investment decision were reclassified from Other noncurrent assets to CWIP within Property, plant and equipment on the Consolidated Balance Sheets as of September 30, 2026, and are reflected as investing activities in the Consolidated Statement of Cash Flows. Additionally, $11.0
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Index
Note 2 - 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 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. | ||||||||
| ASU 2026-02 Environmental Credits and Environmental Credit Obligations | In May 2026, the FASB issued guidance on recognition, measurement, presentation, and disclosure requirements for entities that generate, purchase, or receive environmental credits or have environmental compliance obligations that may be settled with environmental credits. | 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. | ||||||||
Note 3 - Discontinued operations
Discontinued operations includes certain costs associated with legacy business activities other than certain general and administrative costs (reflected in operation and maintenance expense) and interest expense, which were previously allocated to the Company's former businesses which do not meet the criteria for discontinued operations.
On October 31, 2024, the Company completed the separation of Everus, its former construction services segment, into a new independent, publicly-traded company. As a result of the separation, the Company provided to Everus and Everus provided to the Company transition services in accordance with the TSA entered into on October 31, 2024. The Company did not provide nor receive any transition services for the three months ended September 30, 2026. For the nine months ended September 30, 2026, the Company received $1.3 million for these related activities. For the three and nine months ended September 30, 2025, the Company received $1.3 million and $6.8 million, respectively, and paid $17,000 and $42,000 , respectively, for these related activities. All transition services were completed as of March 31, 2026.
Separation related costs for the three months ended September 30, 2026 were not material. Separation related costs of $131,000 , net of tax, were incurred during the nine months ended September 30, 2026 and $39,000 and $586,000 , net of tax, for the three and nine months ended September 30, 2025, respectively. In the second quarter of 2026, the Company recorded a tax benefit of $1.5 million related to an election for a change in tax method for certain strategic initiative costs. Separation costs incurred and the tax benefit are presented in Discontinued operations, net of tax in the Consolidated Statements of Income. Separation costs primarily relate to transaction and third-party support costs, one-time business separation fees and related tax charges.
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Index
The Company had no assets or liabilities related to the discontinued operations of Everus on its balance sheet as of September 30, 2026, September 30, 2025, or December 31, 2025.
The reconciliation of the major classes of income and expense constituting pretax income (loss) from discontinued operations to the after-tax income (loss) from discontinued operations on the Consolidated Statements of Income were as follows:
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Operating revenues | $ | $ | $ | $ | ||||||||||
| Operating expenses | ( | |||||||||||||
| Operating (loss) income | ( | ( | ||||||||||||
| Income (loss) from discontinued operations before income taxes | ( | ( | ||||||||||||
Income tax benefit | ( | ( | ( | |||||||||||
| Discontinued operations, net of tax | $ | $ | ( | $ | $ | ( | ||||||||
Note 4 - Seasonality of operations
Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.
Note 5 - 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.
Details of the Company's expected credit losses were as follows:
| Electric | Natural gas distribution | Pipeline | Total | |||||||||||
| (In thousands) | ||||||||||||||
At December 31, 2025 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ||||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At March 31, 2026 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ||||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At June 30, 2026 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ||||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At September 30, 2026 | $ | $ | $ | $ | ||||||||||
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Index
| Electric | Natural gas distribution | Pipeline | Total | |||||||||||
| (In thousands) | ||||||||||||||
At December 31, 2024 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ||||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At March 31, 2025 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ( | |||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At June 30, 2025 | $ | $ | $ | $ | ||||||||||
| Current expected credit loss provision | ||||||||||||||
| Less write-offs charged against the allowance | ||||||||||||||
| Credit loss recoveries collected | ||||||||||||||
| At September 30, 2025 | $ | $ | $ | $ | ||||||||||
Note 6 - Inventories and natural gas in storage
| September 30, 2026 | September 30, 2025 | December 31, 2025 | |||||||||
| (In thousands) | |||||||||||
| Natural gas in storage (current) | $ | $ | $ | ||||||||
| Fuel stock | |||||||||||
| Total | $ | $ | $ | ||||||||
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Index
Note 7 - Earnings per share
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands, except per share amounts) | ||||||||||||||
| Weighted average common shares outstanding - basic | ||||||||||||||
| Effect of dilutive performance share awards and restricted stock units | ||||||||||||||
| Weighted average common shares outstanding - diluted | ||||||||||||||
| Earnings per share - basic: | ||||||||||||||
| Income from continuing operations | $ | $ | $ | $ | ||||||||||
| Discontinued operations, net of tax | ||||||||||||||
| Earnings per share - basic | $ | $ | $ | $ | ||||||||||
| Earnings per share - diluted: | ||||||||||||||
| Income from continuing operations | $ | $ | $ | $ | ||||||||||
| Discontinued operations, net of tax | ||||||||||||||
| Earnings per share - diluted | $ | $ | $ | $ | ||||||||||
| Shares excluded from the calculation of diluted earnings per share | ||||||||||||||
| Dividends declared per common share | $ | $ | $ | $ | ||||||||||
Note 8 - Equity
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 enter into any FSAs related to the EDA. As of September 30, 2026, the Company had capacity to issue up to an aggregate gross sales price of $310.0 million in shares of common stock under the ATM offering program. Details of the Company's ATM offering activity were as follows:
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Shares issued | ||||||||||||||
| Net proceeds | $ | $ | $ | $ | ||||||||||
| Issuance costs | $ | $ | $ | $ | ||||||||||
Equity forward sale agreements
On December 5, 2025, the Company completed a follow-on public offering of 10.2 million 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 1.5 million 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.
In March 2026, the Company partially settled the FSAs with physical delivery of 4.3 million shares of common stock to the counterparties in exchange for cash of $81.3 million. At September 30, 2026, the Company could have settled all of its outstanding FSAs with physical delivery of 7.4 million shares of common stock to the banking counterparties in exchange for cash of approximately $139.6 million. If the FSAs had been net cash or net share settled at September 30, 2026, the Company, in aggregate, would have been entitled to a net settlement of approximately $2.8 million or 153,231 shares, respectively.
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Index
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 meet 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 were and 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 7.
Note 9 - 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.
Under 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.
Disaggregation
In the following tables, 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.
| Three Months Ended September 30, 2026 | Electric | Natural gas distribution | Pipeline | Other | Total | ||||||||||||
| (In thousands) | |||||||||||||||||
| Residential utility sales | $ | $ | $ | $ | $ | ||||||||||||
Commercial utility sales* | |||||||||||||||||
| Industrial utility sales | |||||||||||||||||
| Other utility sales | |||||||||||||||||
| Natural gas transportation | |||||||||||||||||
| Natural gas storage | |||||||||||||||||
| Other | |||||||||||||||||
| Intersegment eliminations | ( | ( | ( | ( | ( | ||||||||||||
| Revenues from contracts with customers | |||||||||||||||||
| Other revenues | ( | ( | |||||||||||||||
| Total external operating revenues | $ | $ | $ | $ | $ | ||||||||||||
*Commercial utility sales includes the impact from data centers at the electric segment. | |||||||||||||||||
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Index
| Three Months Ended September 30, 2025 | Electric | Natural gas distribution | Pipeline | Other | Total | ||||||||||||
| (In thousands) | |||||||||||||||||
| Residential utility sales | $ | $ | $ | $ | $ | ||||||||||||
| Commercial utility sales* | |||||||||||||||||
| Industrial utility sales | |||||||||||||||||
| Other utility sales | |||||||||||||||||
| Natural gas transportation | |||||||||||||||||
| Natural gas storage | |||||||||||||||||
| Other | |||||||||||||||||
| Intersegment eliminations | ( | ( | ( | ( | ( | ||||||||||||
| Revenues from contracts with customers | |||||||||||||||||
| Other revenues | ( | ||||||||||||||||
| Total external operating revenues | $ | $ | $ | $ | $ | ||||||||||||
*Commercial utility sales includes the impact from data centers at the electric segment. | |||||||||||||||||
| Nine Months Ended September 30, 2026 | Electric | Natural gas distribution | Pipeline | Other | Total | ||||||||||||
| (In thousands) | |||||||||||||||||
| Residential utility sales | $ | $ | $ | $ | $ | ||||||||||||
| Commercial utility sales* | |||||||||||||||||
| Industrial utility sales | |||||||||||||||||
| Other utility sales | |||||||||||||||||
| Natural gas transportation | |||||||||||||||||
| Natural gas storage | |||||||||||||||||
| Other | |||||||||||||||||
| Intersegment eliminations | ( | ( | ( | ( | ( | ||||||||||||
| Revenues from contracts with customers | ( | ||||||||||||||||
Other revenues | ( | ||||||||||||||||
| Total external operating revenues | $ | $ | $ | $ | ( | $ | |||||||||||
*Commercial utility sales includes the impact from data centers at the electric segment. | |||||||||||||||||
| Nine Months Ended September 30, 2025 | Electric | Natural gas distribution | Pipeline | Other | Total | ||||||||||||
| (In thousands) | |||||||||||||||||
| Residential utility sales | $ | $ | $ | $ | $ | ||||||||||||
| Commercial utility sales* | |||||||||||||||||
| Industrial utility sales | |||||||||||||||||
| Other utility sales | |||||||||||||||||
| Natural gas transportation | |||||||||||||||||
| Natural gas storage | |||||||||||||||||
| Other | |||||||||||||||||
| Intersegment eliminations | ( | ( | ( | ( | ( | ||||||||||||
| Revenues from contracts with customers | |||||||||||||||||
| Other revenues | ( | ||||||||||||||||
| Total external operating revenues | $ | $ | $ | $ | $ | ||||||||||||
*Commercial utility sales includes the impact from data centers at the electric segment. | |||||||||||||||||
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Index
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, storage 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 five years and four years , respectively.
At September 30, 2026, 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) | |||||||||||
| $ | $ | $ | $ | ||||||||
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Index
Note 10 - Regulatory matters
Regulatory assets and liabilities
The following table summarizes the individual components of unamortized regulatory assets and liabilities:
Estimated Recovery or Refund Period as of September 30, 2026 | * | September 30, 2026 | September 30, 2025 | December 31, 2025 | |||||||||||||
| (In thousands) | |||||||||||||||||
| Regulatory assets: | |||||||||||||||||
| Current: | |||||||||||||||||
| Environmental compliance programs | Up to | $ | $ | $ | |||||||||||||
| Conservation programs | Up to | ||||||||||||||||
Decoupling mechanisms | Up to | ||||||||||||||||
| Cost recovery mechanisms | Up to | ||||||||||||||||
| Demand charges | Up to | ||||||||||||||||
| Natural gas costs recoverable through rate adjustments | Up to | ||||||||||||||||
| Electric fuel and purchased power deferral | Up to | ||||||||||||||||
| Other | Up to | ||||||||||||||||
| Noncurrent: | |||||||||||||||||
| Pension and postretirement benefits | ** | ||||||||||||||||
| Cost recovery mechanisms | Up to | ||||||||||||||||
| Plant costs/asset retirement obligations | Over plant lives | ||||||||||||||||
| Manufactured gas plant site remediation | - | ||||||||||||||||
| Taxes recoverable from customers | Over plant lives | ||||||||||||||||
| Environmental compliance programs | - | ||||||||||||||||
| Covid-19 deferred costs | Up to | ||||||||||||||||
| Long-term debt refinancing costs | Up to | ||||||||||||||||
| Other | Up to | ||||||||||||||||
| Total regulatory assets | $ | $ | $ | ||||||||||||||
| Regulatory liabilities: | |||||||||||||||||
| Current: | |||||||||||||||||
| Environmental compliance programs | Up to | $ | $ | $ | |||||||||||||
| Natural gas costs refundable through rate adjustments | Up to | ||||||||||||||||
| Electric fuel and purchased power deferral | Up to | ||||||||||||||||
| Margin sharing | Up to | ||||||||||||||||
| Provision for rate refund | Up to | ||||||||||||||||
| Taxes refundable to customers | Up to | ||||||||||||||||
| Conservation programs | Up to | ||||||||||||||||
| Other | Up to | ||||||||||||||||
| Noncurrent: | |||||||||||||||||
| Plant removal and decommissioning costs | Over plant lives | ||||||||||||||||
| Taxes refundable to customers | Over plant lives | ||||||||||||||||
| Cost recovery mechanisms | Up to | ||||||||||||||||
| Accumulated deferred investment tax credit | Over plant lives | ||||||||||||||||
| Pension and postretirement benefits | ** | ||||||||||||||||
| Other | Up to | ||||||||||||||||
| Total regulatory liabilities | $ | $ | $ | ||||||||||||||
| Net regulatory position | $ | ( | $ | ( | $ | ( | |||||||||||
*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. | |||||||||||||||||
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Index
As of September 30, 2026 and 2025, and December 31, 2025, approximately $185.2 million, $175.9 million and $174.3 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, estimated future cost of manufactured gas plant site remediation and certain pipeline integrity cost recovery mechanisms.
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 in certain states. 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 tables summarize 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 | Montana | September 30, 2025 | % | $ | % | •Settlement filed •Interim rate increase of $ | •Investments, including Badger Wind Farm •Corresponding depreciation on those investments •Increased operation and maintenance expense | ||||||||||||||||
| Natural Gas Distribution | Washington | May 29, 2026 | Rate Year 1 Rate Year 2 | Rate Year 1 $ Rate Year 2 $ | % | •Pending | •Multi-year rate case •Infrastructure investments necessary to provide safe and reliable service •Higher operating costs and depreciation tied to system improvements | ||||||||||||||||
Pipeline | FERC | May 29, 2026 | % | $ | % | •Pending •Rates to be effective December 1, 2026 | •Increase in proposed depreciation rates represent | ||||||||||||||||
| Electric | North Dakota | June 30, 2026 | % | $ | % | •Pending •Interim rate increase of $ | •Increase in operations and maintenance expense •Investments made across the system since the last filing •Higher depreciation expense related to infrastructure investments | ||||||||||||||||
| Natural Gas Distribution | Minnesota | October 30, 2026 | % | $ | % | •Pending •Interim rate increase of $ | •Increase in operations and maintenance expense •Investments made across the system since the last filing •Higher depreciation expense related to infrastructure investments | ||||||||||||||||
21
Index
| 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 | Rate Year 1 Rate Year 2 | Rate Year 1 $ Rate Year 2 $ | % | •Approved •Final rates effective March 5, 2025 •$ •Final rates effective March 1, 2026 •$ | •Multi-year rate case •Infrastructure investments necessary to provide safe and reliable service •Higher operating costs due to inflation •$ •$ | ||||||||||||||||
| Electric | Wyoming | June 30, 2025 | % | $ | % | •Approved •Final rates effective April 1, 2026 | •Increases in operation and maintenance expense •Investments made since the last rate case •Corresponding depreciation on those infrastructure investments •Withdrew the requested Reliability and Safety Rider | ||||||||||||||||
| Natural Gas Distribution | Oregon | November 25, 2025 | % | $ | % | •Approved •Final rates effective October 31, 2026 | •Rate base growth •Growth in operations and maintenance expense •Growth in depreciation expense associated with new investments in rate base | ||||||||||||||||
*Annual revenue increase, percent increase and ROE 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. **Reflects a reduction to revenues resulting from a provisional plant review. The adjustment applies retroactively to the original rate effective date. As a result, the Company is required to refund customers for amounts over collected during the retroactive period. | |||||||||||||||||||||||
| Segment | State | Filing Date | Annual Revenue Increase (In millions) | Status | Key Drivers and Additional Information | ||||||||||||
| Other Filings | |||||||||||||||||
| Natural Gas Distribution | Wyoming | August 15, 2025 | N/A | Request denied May 19, 2026 | 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 | Withdrawn as part of rate case settlement agreement | Systems Management Cost Adjustment Mechanism •Recovery of transmission and wildfire related costs | ||||||||||||
| Electric | South Dakota | October 31, 2025 | $ | Approved Rates effective July 1, 2026 | 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 11 - 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 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.
22
Index
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.
Note 12 - 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.
| September 30, 2026 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||||
| (In thousands) | ||||||||||||||
| Mortgage-backed securities | $ | $ | $ | $ | ||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||
| September 30, 2025 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||||
| (In thousands) | ||||||||||||||
| Mortgage-backed securities | $ | $ | $ | $ | ||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||
| December 31, 2025 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||||
| (In thousands) | ||||||||||||||
| Mortgage-backed securities | $ | $ | $ | $ | ||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||
23
Index
The Company's assets measured at fair value on a recurring basis were as follows:
| Fair Value Measurements at September 30, 2026, Using | ||||||||||||||
| Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at September 30, 2026 | |||||||||||
| (In thousands) | ||||||||||||||
| Assets: | ||||||||||||||
| Money market funds | $ | $ | $ | $ | ||||||||||
| Insurance contracts* | ||||||||||||||
| Available-for-sale securities: | ||||||||||||||
| Mortgage-backed securities | ||||||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total assets measured at fair value | $ | $ | $ | $ | ||||||||||
*The insurance contracts invest approximately | ||
| Fair Value Measurements at September 30, 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 September 30, 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Assets: | ||||||||||||||
| Money market funds | $ | $ | $ | $ | ||||||||||
| Insurance contracts* | ||||||||||||||
| Available-for-sale securities: | ||||||||||||||
| Mortgage-backed securities | ||||||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total assets measured at fair value | $ | $ | $ | $ | ||||||||||
*The insurance contracts invest approximately | ||
| 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 | $ | $ | $ | $ | ||||||||||
| Insurance contracts* | ||||||||||||||
| Available-for-sale securities: | ||||||||||||||
| Mortgage-backed securities | ||||||||||||||
| U.S. Treasury securities | ||||||||||||||
| Total assets measured at fair value | $ | $ | $ | $ | ||||||||||
*The insurance contracts invest approximately | ||
24
Index
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.
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 was as follows:
| September 30, 2026 | September 30, 2025 | December 31, 2025 | |||||||||
| (In thousands) | |||||||||||
| Carrying amount | $ | $ | $ | ||||||||
| Fair value | $ | $ | $ | ||||||||
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
Note 13 - Debt
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. The Company and its subsidiaries were in compliance with applicable covenants at September 30, 2026. 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. The Company's borrowings under the commercial paper program and 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.
The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries:
| Company | Debt-to-Total Capitalization Ratio at September 30, 2026 | Provisions for Increased Borrowings, up to a maximum of: | Facility Limit | Amount Outstanding at September 30, 2026 | Amount Outstanding at September 30, 2025 | Amount Outstanding at December 31, 2025 | Letters of Credit at September 30, 2026 | Expiration Date | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Montana-Dakota Utilities Co. | % | $ | $ | $ | $ | $ | $ | 12/11/30 | ||||||||||||||||||
| Cascade Natural Gas Corporation | % | $ | $ | $ | $ | $ | $ | 12/11/30 | ||||||||||||||||||
| Intermountain Gas Company | % | $ | $ | $ | $ | $ | $ | 12/11/30 | ||||||||||||||||||
| MDU Resources Group, Inc. | % | $ | $ | $ | $ | $ | $ | 12/11/30 | ||||||||||||||||||
25
Index
Long-term Debt Outstanding
Long-term debt outstanding was as follows:
Weighted Average Interest Rate at September 30, 2026 | September 30, 2026 | September 30, 2025 | December 31, 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Senior Notes due on dates ranging from August 23, 2028 to June 15, 2062 | % | $ | $ | $ | ||||||||||
| Credit agreements due on December 11, 2030 | % | |||||||||||||
| Commercial paper supported by revolving credit agreement | % | |||||||||||||
| Term Loan Agreements due on dates ranging from March 31, 2027 to March 31, 2039 | % | |||||||||||||
| Medium-Term Notes due on dates ranging from September 15, 2027 to March 16, 2029 | % | |||||||||||||
| Other notes due on November 30, 2038 | % | |||||||||||||
| Less unamortized debt issuance costs | ||||||||||||||
| Total long-term debt | ||||||||||||||
| Less current maturities | ||||||||||||||
| Net long-term debt | $ | $ | $ | |||||||||||
Montana-Dakota 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. In 2026, Montana-Dakota paid down the $250.0 million outstanding balance under the term loan agreement. The term loan was terminated upon pay-off.
On June 16, 2026, Montana-Dakota entered into a NPA to issue $225.0 million of senior notes, with a maturity date of August 18, 2057, at an interest rate of 6.17 percent. The $225.0 million was issued on August 18, 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.
Intermountain On September 22, 2026, Intermountain entered into a NPA to issue $60.0 million of senior notes, with a maturity date of September 22, 2036, at an interest rate of 5.90 percent. The agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. Other covenants include minimum interest coverage ratio and restrictions on the sale of certain assets.
Cascade On August 24, 2026, Cascade entered into a NPA to issue $100.0 million of senior notes, with maturity dates of August 24, 2036, and August 24, 2046, at a weighted average interest rate of 5.96 percent. The agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. Other covenants include minimum interest coverage ratio and restrictions on the sale of certain assets.
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 September 30, 2026, 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.
WBI Energy Transmission's ratio of total debt to total capitalization at September 30, 2026 was 39 percent.
26
Index
Note 14 - Business segment data
The Company's CODM regularly reviews discrete financial information of each reportable segment and uses net income to assess the 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 and other coverages. In addition, the Other category includes certain assets, liabilities and tax adjustments of the holding company primarily associated with corporate functions. Also included are certain general and administrative costs (reflected in operation and maintenance expense) and interest expense, which were previously allocated to the Company's former businesses which do not meet the criteria for discontinued operations.
Discontinued operations includes certain costs associated with legacy business activities other than certain general and administrative costs and interest expense as described above.
27
Index
The information below follows the same accounting policies as described in Note 2 of the Notes to Consolidated Financial Statements in the 2025 Annual Report. Information on the Company's segments was as follows:
| Three Months Ended September 30, 2026 | Electric | Natural gas distribution | Pipeline | Other | Consolidated | ||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Operating revenues: | |||||||||||||||||||||||||||||
| External operating revenues | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
| Intersegment operating revenues | |||||||||||||||||||||||||||||
| Purchased natural gas sold: | |||||||||||||||||||||||||||||
| External purchased natural gas sold | |||||||||||||||||||||||||||||
| Intersegment purchased natural gas sold | |||||||||||||||||||||||||||||
| Electric fuel and purchased power | |||||||||||||||||||||||||||||
| Operation and maintenance: | |||||||||||||||||||||||||||||
| External operation and maintenance | |||||||||||||||||||||||||||||
| Intersegment operation and maintenance | |||||||||||||||||||||||||||||
| Depreciation and amortization | |||||||||||||||||||||||||||||
| Taxes, other than income | |||||||||||||||||||||||||||||
| Other income: | |||||||||||||||||||||||||||||
| External other income | ( | ||||||||||||||||||||||||||||
| Intersegment other income | |||||||||||||||||||||||||||||
| Interest expense: | |||||||||||||||||||||||||||||
| External interest expense | |||||||||||||||||||||||||||||
| Intersegment interest expense | |||||||||||||||||||||||||||||
| Income tax expense (benefit) | ( | ||||||||||||||||||||||||||||
| Income (loss) from continuing operations | ( | ( | |||||||||||||||||||||||||||
| Discontinued operations, net of tax | |||||||||||||||||||||||||||||
Net income (loss) | $ | $ | ( | $ | $ | ( | $ | ||||||||||||||||||||||
28
Index
| Three Months Ended September 30, 2025 | Electric | Natural gas distribution | Pipeline | Other | Consolidated | ||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Operating revenues: | |||||||||||||||||||||||||||||
| External operating revenues | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
| Intersegment operating revenues | |||||||||||||||||||||||||||||
| Purchased natural gas sold: | |||||||||||||||||||||||||||||
| External purchased natural gas sold | |||||||||||||||||||||||||||||
| Intersegment purchased natural gas sold | |||||||||||||||||||||||||||||
| Electric fuel and purchased power | |||||||||||||||||||||||||||||
| Operation and maintenance: | |||||||||||||||||||||||||||||
| External operation and maintenance | ( | ||||||||||||||||||||||||||||
| Intersegment operation and maintenance | |||||||||||||||||||||||||||||
| Depreciation and amortization | |||||||||||||||||||||||||||||
| Taxes, other than income | |||||||||||||||||||||||||||||
| Other income: | |||||||||||||||||||||||||||||
| External other income | |||||||||||||||||||||||||||||
| Intersegment other income | |||||||||||||||||||||||||||||
| Interest expense: | |||||||||||||||||||||||||||||
| External interest expense | |||||||||||||||||||||||||||||
| Intersegment interest expense | |||||||||||||||||||||||||||||
| Income tax expense (benefit) | ( | ||||||||||||||||||||||||||||
Income (loss) from continuing operations | ( | ( | |||||||||||||||||||||||||||
| Discontinued operations, net of tax | ( | ( | |||||||||||||||||||||||||||
Net income (loss) | $ | $ | ( | $ | $ | ( | $ | ||||||||||||||||||||||
29
Index
| Nine Months Ended September 30, 2026 | Electric | Natural gas distribution | Pipeline | Other | Consolidated | ||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Operating revenues: | |||||||||||||||||||||||||||||
| External operating revenues | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
| Intersegment operating revenues | |||||||||||||||||||||||||||||
| Purchased natural gas sold: | |||||||||||||||||||||||||||||
| External purchased natural gas sold | |||||||||||||||||||||||||||||
| Intersegment purchased natural gas sold | |||||||||||||||||||||||||||||
| Electric fuel and purchased power | |||||||||||||||||||||||||||||
| Operation and maintenance: | |||||||||||||||||||||||||||||
| External operation and maintenance | |||||||||||||||||||||||||||||
| Intersegment operation and maintenance | |||||||||||||||||||||||||||||
| Depreciation and amortization | |||||||||||||||||||||||||||||
| Taxes, other than income | |||||||||||||||||||||||||||||
| Other income: | |||||||||||||||||||||||||||||
| External other income | ( | ||||||||||||||||||||||||||||
| Intersegment other income | |||||||||||||||||||||||||||||
| Interest expense: | |||||||||||||||||||||||||||||
| External interest expense | |||||||||||||||||||||||||||||
| Intersegment interest expense | |||||||||||||||||||||||||||||
Income tax (benefit) expense | ( | ||||||||||||||||||||||||||||
| Income (loss) from continuing operations | ( | ||||||||||||||||||||||||||||
| Discontinued operations, net of tax | |||||||||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
30
Index
| Nine Months Ended September 30, 2025 | Electric | Natural gas distribution | Pipeline | Other | Consolidated | ||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Operating revenues: | |||||||||||||||||||||||||||||
| External operating revenues | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
| Intersegment operating revenues | |||||||||||||||||||||||||||||
| Purchased natural gas sold: | |||||||||||||||||||||||||||||
| External purchased natural gas sold | |||||||||||||||||||||||||||||
| Intersegment purchased natural gas sold | |||||||||||||||||||||||||||||
| Electric fuel and purchased power | |||||||||||||||||||||||||||||
| Operation and maintenance: | |||||||||||||||||||||||||||||
| External operation and maintenance | ( | ||||||||||||||||||||||||||||
| Intersegment operation and maintenance | |||||||||||||||||||||||||||||
| Depreciation and amortization | |||||||||||||||||||||||||||||
| Taxes, other than income | |||||||||||||||||||||||||||||
| Other income: | |||||||||||||||||||||||||||||
| External other income | |||||||||||||||||||||||||||||
| Intersegment other income | |||||||||||||||||||||||||||||
| Interest expense: | |||||||||||||||||||||||||||||
| External interest expense | |||||||||||||||||||||||||||||
| Intersegment interest expense | |||||||||||||||||||||||||||||
Income tax (benefit) expense | ( | ||||||||||||||||||||||||||||
| Income (loss) from continuing operations | ( | ||||||||||||||||||||||||||||
| Discontinued operations, net of tax | ( | ( | |||||||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
A reconciliation of reportable segment operating revenues to consolidated operating revenues is as follows:
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Operating revenues reconciliation: | ||||||||||||||
| Total reportable segment operating revenues | $ | $ | $ | $ | ||||||||||
| Other revenue | ||||||||||||||
| Elimination of intersegment operating revenues | ( | ( | ( | ( | ||||||||||
| Total consolidated operating revenues | $ | $ | $ | $ | ||||||||||
Note 15 - Employee benefit plans
Pension and other postretirement plans
The Company has noncontributory qualified defined benefit pension plans and other postretirement benefit plans for certain eligible employees.
Components of net periodic benefit cost for the Company's pension benefit plans were as follows:
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Components of net periodic benefit cost: | ||||||||||||||
| Interest cost | $ | $ | $ | $ | ||||||||||
| Expected return on assets | ( | ( | ( | ( | ||||||||||
| Amortization of net actuarial loss | ||||||||||||||
| Net periodic benefit cost | $ | $ | $ | $ | ||||||||||
31
Index
Components of net periodic benefit credit for the Company's other postretirement benefit plans were as follows:
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||
| (In thousands) | ||||||||||||||
| Components of net periodic benefit credit: | ||||||||||||||
| Service cost | $ | $ | $ | $ | ||||||||||
| Interest cost | ||||||||||||||
| Expected return on assets | ( | ( | ( | ( | ||||||||||
| Amortization of prior service credit | ( | ( | ( | ( | ||||||||||
| Amortization of net actuarial gain | ( | ( | ( | ( | ||||||||||
| Net periodic benefit credit, including amount capitalized | ( | ( | ( | ( | ||||||||||
| Less amount capitalized | ||||||||||||||
| Net periodic benefit credit | $ | ( | $ | ( | $ | ( | $ | ( | ||||||
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. The service cost component is included in Operation and maintenance expense on the Consolidated Statements of Income.
Nonqualified defined 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. The Company's net periodic benefit cost for these plans was $662,000 and $716,000 for the three months ended September 30, 2026 and 2025, respectively, and $2.0 million and $2.1 million for the nine months ended September 30, 2026 and 2025, respectively. The components of net periodic benefit cost for these plans are included in Other income on the Consolidated Statements of Income.
Note 16 - 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 September 30, 2026 and 2025, and December 31, 2025, the Company accrued liabilities, which have not been discounted, of $23.8 million, $25.1 million and $26.1 million, respectively. The Company also recorded corresponding receivables of $96,000 , $1.9 million, and $1.6 million, at September 30, 2026 and 2025, and December 31, 2025, respectively. The Company recorded regulatory assets of $22.0 million, $22.1 million and $23.2 million, at September 30, 2026 and 2025, and December 31, 2025, 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, which was paid in February 2026.
Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of 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
The Company is a party to claims for the cleanup of environmental contamination at certain manufactured gas plant sites. There were no material changes to the Company's environmental matters that were previously reported in the 2025 Annual Report.
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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 September 30, 2026, the fixed maximum amounts guaranteed under these letters of credit aggregated $8.5 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 September 30, 2026. 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 September 30, 2026, approximately $15.3 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheets.
Leases
The Company's leases primarily include operating leases for equipment, buildings, easements and vehicles. The Company leases certain equipment to third parties through its utility business, which are considered short-term operating leases with terms of less than 12 months. Lease revenue was not material for the three and nine months ended September 30, 2026 or 2025. At September 30, 2026, the Company had no lease receivables.
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 September 30, 2026, 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 $22.1 million.
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Item 2. 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.
Dividends In August 2026, the Company's board of directors revised the Company's long term dividend payout ratio target to 55 percent to 65 percent of earnings compared to the previous target of 60 percent to 70 percent of regulated energy delivery earnings. The revised range is intended to provide the Company with greater flexibility to fund its capital investment program, reduce future equity needs and support the Company's long-term growth. The Company has an 88-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.
Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, higher 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. For more information specific to each of the Company's businesses, see the following discussion in each business segment's Outlook section. For more information on the possible impacts, see Item 1A. Risk Factors in this quarterly report and Part I, Item 1A. Risk Factors in the 2025 Annual Report.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q 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, dividend payout ratio targets, customer rates, regulatory approvals, sustainability, strategies and other such matters, are forward-looking statements. 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 in this quarterly report and Part I, Item 1A. Risk Factors in the 2025 Annual Report and subsequent filings with the SEC. 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.
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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.
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||
| Electric | $ | 26.5 | $ | 21.5 | $ | 55.7 | $ | 46.9 | |||||||||
| Natural gas distribution | (20.7) | (18.2) | 19.6 | 19.1 | |||||||||||||
| Pipeline | 13.1 | 16.8 | 42.8 | 49.4 | |||||||||||||
| Other | (4.8) | (1.7) | (3.8) | (.4) | |||||||||||||
| Income from continuing operations | 14.1 | 18.4 | 114.3 | 115.0 | |||||||||||||
| Discontinued operations, net of tax | (.1) | — | 1.8 | (.9) | |||||||||||||
| Net income | $ | 14.0 | $ | 18.4 | $ | 116.1 | $ | 114.1 | |||||||||
| Earnings per share - basic: | |||||||||||||||||
| Income from continuing operations | $ | .07 | $ | .09 | $ | .55 | $ | .56 | |||||||||
| Discontinued operations, net of tax | — | — | .01 | — | |||||||||||||
| Earnings per share - basic | $ | .07 | $ | .09 | $ | .56 | $ | .56 | |||||||||
| Earnings per share - diluted: | |||||||||||||||||
| Income from continuing operations | $ | .07 | $ | .09 | $ | .54 | $ | .56 | |||||||||
| Discontinued operations, net of tax | — | — | .01 | — | |||||||||||||
| Earnings per share - diluted | $ | .07 | $ | .09 | $ | .55 | $ | .56 | |||||||||
Three Months Ended September 30, 2026, Compared to Three Months Ended September 30, 2025 The Company's consolidated earnings decreased $4.4 million. Drivers of the earnings decrease include:
•The electric business earnings increase was largely driven by higher retail sales revenue from new rates approved in regulatory proceedings in North Dakota, Montana and Wyoming and from recovery mechanisms associated with renewable investments, including Badger Wind Farm. Higher retail sales volumes across all customer classes, largely due to warmer weather, further drove the increase. Higher costs associated with Badger Wind Farm, including operation and maintenance, interest and depreciation expense, partially offset the increase. Lower returns on nonqualified benefit plan investments also impacted results.
•The natural gas distribution business reported an increased seasonal loss, primarily driven by higher operation and maintenance expense, including higher payroll-related costs and a $2.1 million loss, net of tax, on the Company's decision to discontinue development of the Knott Landfill RNG project. Higher interest expense resulting from higher long-term debt balances and lower returns on nonqualified benefit plan investments also contributed to the loss. These impacts were partially offset by new rates approved in regulatory proceedings primarily in Idaho and Washington, as well as higher retail sales volumes across all customer classes.
•The earnings decrease at the pipeline business was driven by higher operation and maintenance expense primarily attributable to higher payroll-related and material costs as well as consulting costs associated with its recently filed rate case. Lower storage injections, advisory costs associated with Bakken East, and lower returns on the Company's nonqualified benefit plans further drove the decrease. The decrease was partially offset by short-term natural gas transportation contracts, as well as contributions from previously constructed growth projects, including a contracted volume increase.
•Other experienced an increase in net loss primarily due to higher claims experience at the captive insurer and higher income tax expense due to income tax adjustments related to the company's annualized estimated tax rate.
Nine Months Ended September 30, 2026, Compared to Nine Months Ended September 30, 2025 The Company's consolidated earnings increased $2.0 million. Drivers of the earnings increase include:
•The electric business earnings increase was largely the result of higher retail sales revenue, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm. New rates approved in regulatory proceedings in Montana, Wyoming and North Dakota further drove the increase. Higher costs associated with Badger Wind Farm, including operation and maintenance, interest and depreciation expense partially offset the increase.
•The natural gas distribution business reported an increase in earnings, primarily driven by new rates in Idaho, Washington, Wyoming and Montana. The increase was partially offset by higher operation and maintenance expense, primarily increased payroll-related costs as well as a $2.1 million, net of tax, loss on the Company's decision to discontinue development of the Knott Landfill RNG project. Higher interest expense resulting from higher debt balances, lower retail sales and electric generation transportation volumes due to warmer first quarter weather, and lower other income further offset the increase.
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•The decrease in earnings at the pipeline business was driven by higher operation and maintenance expense primarily attributable to higher payroll-related and materials costs as well as consulting costs associated with its recently filed rate case. The business also incurred advisory costs associated with Bakken East. Lower interruptible natural gas storage withdrawals and higher depreciation on projects placed in service further drove the decrease. The decrease was partially offset by short-term natural gas transportation contracts, as well as contributions from previously constructed growth projects, including a contracted volume increase.
•Other experienced an increase in net loss primarily due to higher claims experience at the captive insurer. Other also reflects income tax adjustments related to the Company’s annualized estimated tax rate. The decrease was partially offset by income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs.
A discussion of key financial data from the Company's business segments follows.
Business Segment Financial and Operating Data
The following sections include key financial and operating data for each of the Company's business segments. Also included are highlights on key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters of the Company's business segments.
For information pertinent to various commitments and contingencies, see the Condensed Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Note 14 of the Condensed Notes to Consolidated Financial Statements.
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 Note 14. 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 Note 10 and the 2025 Annual Report.
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 large power users. 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.
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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 lighting, 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.
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 remain volatile and costs for goods and services also 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 in this quarterly report and Part I, Item 1A. Risk Factors in the 2025 Annual Report.
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 approved by the NDPSC in June 2026.
Earnings overview - The following information summarizes the performance of the electric segment.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating revenues | $ | 142.3 | $ | 117.8 | $ | 379.6 | $ | 328.3 | |||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Electric fuel and purchased power | 48.6 | 41.2 | 133.3 | 119.8 | |||||||||||||||||||
| Operation and maintenance | 30.0 | 26.1 | 90.1 | 84.6 | |||||||||||||||||||
| Depreciation and amortization | 20.2 | 17.4 | 60.1 | 52.0 | |||||||||||||||||||
| Taxes, other than income | 4.8 | 4.7 | 15.7 | 14.2 | |||||||||||||||||||
| Total operating expenses | 103.6 | 89.4 | 299.2 | 270.6 | |||||||||||||||||||
| Operating income | 38.7 | 28.4 | 80.4 | 57.7 | |||||||||||||||||||
| Other income | .2 | 2.0 | 2.5 | 5.7 | |||||||||||||||||||
| Interest expense | 11.3 | 7.6 | 34.4 | 23.1 | |||||||||||||||||||
| Income before income taxes | 27.6 | 22.8 | 48.5 | 40.3 | |||||||||||||||||||
| Income tax (benefit) expense | 1.1 | 1.3 | (7.2) | (6.6) | |||||||||||||||||||
| Net income | $ | 26.5 | $ | 21.5 | $ | 55.7 | $ | 46.9 | |||||||||||||||
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| Operating statistics | Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| Revenues (millions) | |||||||||||||||||
| Retail sales: | |||||||||||||||||
| Residential | $ | 43.6 | $ | 35.7 | $ | 118.0 | $ | 102.2 | |||||||||
Commercial1 | 67.2 | 50.7 | 162.9 | 137.1 | |||||||||||||
| Industrial | 10.4 | 9.5 | 31.3 | 27.4 | |||||||||||||
| Other | 2.2 | 2.0 | 6.2 | 5.5 | |||||||||||||
| 123.4 | 97.9 | 318.4 | 272.2 | ||||||||||||||
| Other | 18.9 | 19.9 | 61.2 | 56.1 | |||||||||||||
| $ | 142.3 | $ | 117.8 | $ | 379.6 | $ | 328.3 | ||||||||||
| Volumes (million kWh) | |||||||||||||||||
| Retail sales: | |||||||||||||||||
| Residential | 320.5 | 297.8 | 905.9 | 904.3 | |||||||||||||
Commercial1 | 787.4 | 707.9 | 2,261.4 | 2,104.5 | |||||||||||||
| Industrial | 124.2 | 121.1 | 373.6 | 357.8 | |||||||||||||
| Other | 22.1 | 21.2 | 61.4 | 61.5 | |||||||||||||
| 1,254.2 | 1,148.0 | 3,602.3 | 3,428.1 | ||||||||||||||
| Average cost of electric fuel and purchased power per kWh | $ | .029 | $ | .027 | $ | .028 | $ | .026 | |||||||||
1Commercial includes the impact from data centers. | |||||||||||||||||
Cooling degree days (% warmer (colder) than prior year)1 | |||||||||||||||||
| Montana | 25.4 | % | (13.0) | % | 17.0 | % | (4.3) | % | |||||||||
| North Dakota | 34.1 | % | (17.0) | % | 25.4 | % | (6.6) | % | |||||||||
| South Dakota | 30.5 | % | 8.6 | % | 25.4 | % | 18.4 | % | |||||||||
| Wyoming | 27.4 | % | (25.2) | % | 21.2 | % | (22.9) | % | |||||||||
1Cooling degree days are a measure of the energy demand for cooling. | |||||||||||||||||
Three Months Ended September 30, 2026, Compared to Three Months Ended September 30, 2025 Electric earnings increased $5.0 million as a result of:
•Revenue increased $24.5 million.
◦Largely due to:
▪Higher fuel and purchased power costs of $7.4 million recovered in customer rates and offset in expense, as described below.
▪New rates approved in regulatory proceedings of $7.1 million in North Dakota, Montana and Wyoming.
▪Higher renewable tracker revenues of $6.2 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax expense, as described below.
▪Higher retail sales volumes of $2.2 million across all customer classes due to warmer weather.
•Electric fuel and purchased power increased $7.4 million, largely the result of higher demand costs and higher volumes.
•Operation and maintenance increased $3.9 million.
◦Largely the result of:
▪Higher contract services of $2.1 million, partially related to Badger Wind Farm.
▪Higher payroll-related costs of $1.0 million.
▪Timing of software expenses.
•Depreciation and amortization increased $2.8 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.
•Taxes, other than income was comparable to the same period in the prior year.
•Other income decreased $1.8 million, largely the result of lower returns on the Company's nonqualified benefit plan investments and absence of TSA income associated with services provided to Everus.
•Interest expense increased $3.7 million, primarily due to higher long-term debt balances.
•Income tax expense decreased $200,000, largely due to higher production tax credits of $1.9 million driven by Badger Wind Farm as discussed above, partially offset by higher income before income taxes.
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Nine Months Ended September 30, 2026, Compared to Nine Months Ended September 30, 2025 Electric earnings increased $8.8 million as a result of:
•Revenue increased $51.3 million.
◦Largely due to:
▪Higher renewable tracker revenues of $20.5 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax benefit, as described below.
▪Higher fuel and purchased power costs of $13.5 million recovered in customer rates and offset in expense, as described below.
▪New rates approved in regulatory proceedings of $10.7 million in Montana, Wyoming and North Dakota.
▪Higher retail sales volumes of $1.4 million across all major customer classes.
•Electric fuel and purchased power increased $13.5 million, largely the result of higher demand costs and higher volumes.
•Operation and maintenance increased $5.5 million.
◦Largely the result of:
▪Higher contract services of $5.5 million, partially related to Badger Wind Farm. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station and Wygen III generating station outage-related costs.
▪Higher payroll-related costs of $2.3 million.
◦Partially offset by timing of software expenses and absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income as described below.
•Depreciation and amortization increased $8.1 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.
•Taxes, other than income increased $1.5 million, largely as a result of higher property tax, primarily in Montana and North Dakota.
•Other income decreased $3.2 million, largely the result of lower TSA income, as described above, and lower AFUDC due to lower average CWIP balances.
•Interest expense increased $11.3 million, primarily due to higher long-term debt balances.
•Income tax benefit increased $600,000, largely due to higher production tax credits of $3.4 million driven by Badger Wind Farm as discussed above, partially offset by higher income before income taxes.
Earnings overview - The following information summarizes the performance of the natural gas distribution segment.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating revenues | $ | 153.0 | $ | 144.3 | $ | 828.1 | $ | 890.5 | |||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Purchased natural gas sold | 62.6 | 62.7 | 439.8 | 519.0 | |||||||||||||||||||
| Operation and maintenance | 63.6 | 56.7 | 189.6 | 180.8 | |||||||||||||||||||
| Depreciation and amortization | 27.0 | 26.6 | 80.0 | 79.2 | |||||||||||||||||||
| Taxes, other than income | 13.0 | 13.3 | 56.3 | 60.9 | |||||||||||||||||||
| Total operating expenses | 166.2 | 159.3 | 765.7 | 839.9 | |||||||||||||||||||
| Operating income (loss) | (13.2) | (15.0) | 62.4 | 50.6 | |||||||||||||||||||
| Other income | 1.8 | 3.9 | 7.9 | 12.3 | |||||||||||||||||||
| Interest expense | 16.7 | 14.7 | 48.9 | 43.3 | |||||||||||||||||||
| Income (loss) before income taxes | (28.1) | (25.8) | 21.4 | 19.6 | |||||||||||||||||||
| Income tax (benefit) expense | (7.4) | (7.6) | 1.8 | 0.5 | |||||||||||||||||||
| Net income (loss) | $ | (20.7) | $ | (18.2) | $ | 19.6 | $ | 19.1 | |||||||||||||||
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| Operating statistics | Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| Revenues (millions) | |||||||||||||||||
| Retail sales: | |||||||||||||||||
| Residential | $ | 72.1 | $ | 67.5 | $ | 442.7 | $ | 465.2 | |||||||||
| Commercial | 43.6 | 43.7 | 257.3 | 296.7 | |||||||||||||
| Industrial | 7.3 | 8.0 | 29.4 | 33.1 | |||||||||||||
| 123.0 | 119.2 | 729.4 | 795.0 | ||||||||||||||
| Transportation and other | 30.0 | 25.1 | 98.7 | 95.5 | |||||||||||||
| $ | 153.0 | $ | 144.3 | $ | 828.1 | $ | 890.5 | ||||||||||
| Volumes (MMdk) | |||||||||||||||||
| Retail sales: | |||||||||||||||||
| Residential | 4.4 | 3.9 | 40.0 | 44.2 | |||||||||||||
| Commercial | 4.8 | 4.7 | 30.8 | 33.6 | |||||||||||||
| Industrial | 1.0 | .9 | 3.6 | 3.6 | |||||||||||||
| 10.2 | 9.5 | 74.4 | 81.4 | ||||||||||||||
| Transportation sales: | |||||||||||||||||
| Commercial | .3 | .3 | 1.2 | 1.4 | |||||||||||||
| Industrial | 40.2 | 42.6 | 111.5 | 129.1 | |||||||||||||
| 40.5 | 42.9 | 112.7 | 130.5 | ||||||||||||||
| Total throughput | 50.7 | 52.4 | 187.1 | 211.9 | |||||||||||||
| Average cost of natural gas per dk | $ | 6.15 | $ | 6.59 | $ | 5.91 | $ | 6.38 | |||||||||
Heating degree days (% colder (warmer) than prior year)1 | |||||||||||||||||
| Idaho | 71.9 | % | (36.0) | % | (13.6) | % | (2.0) | % | |||||||||
| Minnesota | (58.0) | % | 138.1 | % | (6.9) | % | 17.5 | % | |||||||||
| Montana | 77.8 | % | — | % | (23.1) | % | 6.4 | % | |||||||||
North Dakota2 | (22.2) | % | 80.0 | % | (8.8) | % | 13.1 | % | |||||||||
Oregon2 | 184.3 | % | (17.7) | % | (4.0) | % | (1.7) | % | |||||||||
South Dakota2 | (53.8) | % | 23.8 | % | (21.6) | % | 9.8 | % | |||||||||
Washington2 | 185.2 | % | (59.1) | % | (10.3) | % | (4.8) | % | |||||||||
| Wyoming | (19.6) | % | 37.8 | % | (22.8) | % | 10.8 | % | |||||||||
1Heating Degree days are a measure of the daily temperature demand for energy heating. 2Weather normalization or decoupling mechanisms are in place that minimize the weather impact. | |||||||||||||||||
Three Months Ended September 30, 2026, Compared to Three Months Ended September 30, 2025 Natural gas distribution reported an increased seasonal loss of $2.5 million as a result of:
•Revenue increased $8.7 million.
◦Largely due to:
▪New rates approved in regulatory proceedings of $6.5 million, primarily in Idaho and Washington.
▪A 7.1 percent or $1.2 million increase in retail sales volumes to all customer classes.
▪Higher basic service charges of $600,000 due to customer growth.
▪Higher revenue-based taxes of $200,000, recovered in rates and offset in expense, as described below.
•Purchased natural gas sold decreased $100,000, largely due to lower commodity costs of $8.1 million, partially offset by higher volumes of natural gas purchased of $4.4 million, and net environmental compliance costs of $3.5 million.
•Operation and maintenance increased $6.9 million.
◦Largely due to:
▪Higher payroll-related costs of $2.8 million.
▪Loss of $2.7 million for costs related to the Company's decision to discontinue development of the Knott Landfill RNG project.
▪Timing of software expenses.
•Depreciation and amortization increased $400,000, of which $1.4 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 in Washington, Oregon, Wyoming and Montana of $900,000.
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•Taxes, other than income decreased $300,000, due to timing of property taxes in Idaho, partially offset by higher revenue-based taxes, as described above.
•Other income decreased $2.1 million, largely the result of lower returns of $1.3 million on the Company's nonqualified benefit plan investments and the absence of TSA income of $800,000 associated with services provided to Everus.
•Interest expense increased $2.0 million, primarily due to higher long-term debt balances.
•Income tax benefit decreased $200,000, primarily the result of changes in permanent tax adjustments, partially offset by higher seasonal loss before income taxes.
Nine Months Ended September 30, 2026, Compared to Nine Months Ended September 30, 2025 Natural gas distribution earnings increased $500,000 as a result of:
•Revenue decreased $62.4 million.
◦Largely due to:
▪Lower purchased natural gas sold of $79.2 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
▪Lower revenue-based taxes of $4.7 million, recovered in rates and offset in expense, as described below.
▪An 8.6 percent or $2.5 million decrease in retail sales volumes to all customer classes due to warmer weather during the first quarter, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.
▪Transportation volumes decreased 13.6 percent or $2.2 million primarily the result of lower electric generation volumes largely due to warmer weather during the first quarter.
◦Partially offset by:
▪New rates approved in regulatory proceedings of $22.1 million, primarily in Idaho, Washington, Wyoming and Montana.
▪Higher basic service charges of $2.2 million due to customer growth.
▪Higher conservation revenues of $1.2 million that were offset in expense, as described below.
•Purchased natural gas sold decreased $79.2 million, largely due to lower volumes of natural gas purchased of $44.1 million, commodity costs of $28.8 million and net environmental compliance costs of $6.3 million.
•Operation and maintenance increased $8.8 million.
◦Largely due to:
▪Higher payroll-related costs of $6.2 million.
▪Loss of $2.7 million for costs related to the Company's decision to discontinue development of the Knott Landfill RNG project.
▪Higher contract services of $1.7 million, including higher rate case expenses.
▪Higher conservation-related costs, recovered in rates, as discussed above.
▪Higher insurance expenses of $900,000.
◦Partially offset by:
▪Timing of software expenses and absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income, as described below.
•Depreciation and amortization increased $800,000, of which $3.8 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 in Washington, Oregon, Montana and Wyoming of $2.9 million.
•Taxes, other than income decreased $4.6 million, due to lower revenue-based taxes, as described above.
•Other income decreased $4.4 million.
◦Primarily due to:
▪Lower TSA income of $3.2 million, as described above.
▪Lower net interest income on regulatory deferral balances.
•Interest expense increased $5.6 million, primarily due to higher long-term debt balances.
•Income tax expense increased $1.3 million, primarily the result of changes in permanent tax adjustments and higher income before income taxes.
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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 as discussed below. These segments grew rate base by 8.7 percent annually over the last five years on a compound basis and expect 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, these segments experienced retail customer growth of approximately 1.5 percent, 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.
Recent regulatory developments have the potential to impact the operation and compliance strategy for Coyote Station. In December 2024, the EPA issued a final decision on the NDDEQ's Regional Haze state implementation plan, disapproving the state's conclusion that no additional controls are warranted for Coyote Station during this implementation period. In September 2026, the EPA proposed to reverse its December 2024 partial disapproval of the North Dakota State Implementation Plan for regional haze and instead fully approve the state's plan. If finalized, no additional regional haze controls would be required for the North Dakota facilities the EPA previously disapproved, including Coyote Station for this round of regional haze review.
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.
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, equivalent to approximately 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact the power supply available to other customers. The NDPSC approved an electric service agreement to serve an additional 350 MW of data center load with Applied Digital in the Company's service territory. The third HPC building at Ellendale is scheduled to begin ramping in January 2027. A total of 280 MW of Applied Digital's data center load is currently online.
In June 2026, the Company announced the signing of a new electric service agreement to serve Applied Digital's newest data center campus near Center, North Dakota. The electric service agreement supports 430 MWs of HPC load and is currently scheduled to come online in the third quarter of 2027, pending various approvals, including NDPSC approval of the electric service agreement.
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 remains pending, with a hearing scheduled in November 2026. An updated conditional use permit for the data center siting with McPherson County also remains pending.
Growing demand from large-load customers, including data centers, continues to provide opportunities for increased electric sales. The Company's approach to serving large-load customers is grounded in protecting existing customers and ensuring that growth creates value for the electric system and the communities the Company serves. The Company follows the principle of cost causation, meaning the customer that creates a cost should pay that cost. Infrastructure and service costs that are specifically needed to serve a large-load customer are assigned appropriately through contracts, tariffs and regulatory approvals. Benefits associated with these agreements may also flow back to existing customers through approved regulatory mechanisms.
The Company has been selected for or awarded smart grid grant funding under the GRIP program administered through the Bipartisan Infrastructure Law and other programs for the following projects, including a transmission line rebuild between Hettinger and Elgin, North Dakota, incorporating carbon fiber-core conductors and a dynamic line rating system, expected in service mid-2029; replacement of approximately eight miles of aging transmission line near Poplar, Montana to increase capacity and reduce wildfire risk, expected in service November 2029; and sub-transmission upgrades in the Merricourt, North Dakota area to increase load-serving capability and improve reliability, with scheduled in-service dates of October 2028.
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Legislation and rulemaking The Company monitors legislation and rulemaking that may impact its segments. Below are some of the specific actions the Company is monitoring.
•In May 2024, the EPA published four final rules, affecting power sector GHG standards, mercury controls, effluent limits and coal ash management. In March 2025, the EPA announced reconsideration of the Electric Generation and GHG Rule, Mercury and Air Toxics Standards Rule, and Effluent Limitations Guidelines Rule. Depending on final outcomes, compliance costs, and regulatory recovery of compliance costs from customers, these rules could have a material adverse effect on the Company's results of operations and cash flows.
◦In June 2025, the EPA proposed repealing and replacing the May 2024 Electric Generation GHG Rule, with options to (a) exclude the power sector from GHG regulations or (b) remove carbon capture and sequestration requirements while retaining efficiency based standards for natural gas fired combustion units. In September 2026, the EPA released a final rule consistent with option (b). This rule is in litigation. In a supplemental proposal, the EPA proposed rescinding all remaining GHG standards for electric generation. The Company is currently reviewing the rules.
◦In February 2026, the EPA repealed the 2024 Mercury and Air Toxics Standard Rule and restored the 2012 Mercury and Air Toxics Standard Rule, under which the Company’s coal plants maintain compliance. The repeal of the 2024 Mercury and Air Toxics Standard Rule is being litigated by multiple parties.
◦The Company determined that the Effluent Limitations Guidelines Rule and related amendments do not have a material impact on the Company.
◦In April 2026, the EPA proposed amendments to federal regulations for coal combustion residuals at legacy coal ash sites. The Company submitted comments to the EPA in June 2026. A final rule is expected in early 2027.
•In February 2026, the EPA rescinded the 2009 Endangerment Finding and related motor vehicle GHG standards under the Clean Air Act. This action does not directly address or repeal GHG regulations for power plants and other non-motor vehicle sources. The rescinded rules are in litigation.
•In July 2024, the ODEQ published its proposed rules to create a new CPP. The OEQC adopted the rules in November 2024. In April 2026, Cascade joined with 28 other companies, organizations and individuals in filing a lawsuit in the Oregon Court of Appeals challenging the OEQC's statutory authority to adopt the CPP and asking the court to invalidate the CPP. In May 2026, the Oregon Court of Appeals granted a motion to expedite litigation challenging the CPP. The Company will continue to strive to satisfy all requirements set by the CPP while this litigation is underway. The Company intends to meet its obligations through a combination of energy efficiency and conservation measures, no-cost allowances, future purchases of community climate investment credits, and contracted and future purchases of 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. Plaintiffs appealed this decision to 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 in February 2026. In an opinion issued in September 2026, the Ninth Circuit affirmed the dismissal on sovereign immunity grounds. The Ninth Circuit did not rule on the merits of the Plaintiffs' argument that the State Energy Code amendments were preempted by federal law.
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. In September 2026, the Washington State Supreme Court ruled that Initiative Measure No. 2066 is unconstitutional in its entirety. As a result, the provisions contained in Initiative Measure No. 2066 are now void.
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•In June 2026, the Bend, Oregon City Council passed a Climate Pollution Fee to discourage the use of natural gas in new residential construction. The ordinance is set to take effect in April 2027 and fees apply to certain natural gas appliances in new single-family homes, duplexes, townhomes and accessory dwelling units. It does not apply to manufactured homes, triplexes or larger housing developments, existing buildings, renovations, replacements or commercial construction.
Pipeline
Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in Note 14. 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 Minot Expansion Project was placed in service in November 2025 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 remain volatile, and costs for raw material and contract services also remain high. For additional discussion regarding risks and uncertainties, see Item 1A. Risk Factors in this quarterly report and Part I, Item 1A. Risk Factors in the 2025 Annual Report.
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.
Earnings overview - The following information summarizes the performance of the pipeline segment.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating revenues | $ | 56.8 | $ | 57.4 | $ | 170.6 | $ | 170.4 | |||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Operation and maintenance | 22.3 | 21.0 | 65.5 | 62.7 | |||||||||||||||||||
| Depreciation and amortization | 8.4 | 8.1 | 24.9 | 24.0 | |||||||||||||||||||
| Taxes, other than income | 3.9 | 3.7 | 11.4 | 10.6 | |||||||||||||||||||
| Total operating expenses | 34.6 | 32.8 | 101.8 | 97.3 | |||||||||||||||||||
| Operating income | 22.2 | 24.6 | 68.8 | 73.1 | |||||||||||||||||||
| Other income (expense) | (.8) | 1.0 | (.8) | 3.1 | |||||||||||||||||||
| Interest expense | 4.3 | 4.1 | 12.5 | 12.6 | |||||||||||||||||||
| Income before income taxes | 17.1 | 21.5 | 55.5 | 63.6 | |||||||||||||||||||
| Income tax expense | 4.0 | 4.7 | 12.7 | 14.2 | |||||||||||||||||||
| Net income | $ | 13.1 | $ | 16.8 | $ | 42.8 | $ | 49.4 | |||||||||||||||
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| Operating statistics | Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| Transportation volumes (MMdk) | 162.3 | 160.3 | 455.9 | 455.2 | |||||||||||||
| Customer natural gas storage balance (MMdk): | |||||||||||||||||
| Beginning of period | 41.5 | 34.6 | 37.6 | 44.1 | |||||||||||||
| Net injection | 4.7 | 13.6 | 8.6 | 4.1 | |||||||||||||
| End of period | 46.2 | 48.2 | 46.2 | 48.2 | |||||||||||||
Three Months Ended September 30, 2026, Compared to Three Months Ended September 30, 2025 Pipeline earnings decreased $3.7 million as a result of:
•Revenues decreased $600,000 as a result of:
◦Lower interruptible transportation volumes of $900,000.
◦Lower storage-related revenue of $800,000.
◦Partially offset by:
▪Increased demand revenue, largely due to:
•Increased usage of short-term natural gas transportation contracts of $500,000.
•Growth projects placed in service of $400,000.
•Operation and maintenance increased $1.3 million.
◦Primarily from:
▪Higher payroll-related costs of $700,000.
▪Higher materials costs of $600,000.
▪Higher consulting costs associated with the Company's recent rate case filing.
•Depreciation and amortization increased $300,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.
•Taxes, other than income was comparable to the same period in the prior year.
•Other income decreased $1.8 million.
◦Largely due to:
▪Advisory costs associated with Bakken East incurred in 2026 that were not eligible for capitalization of $700,000.
▪Lower investment returns on the Company's non-qualified benefit plans of $500,000.
▪Lower TSA income of $300,000 associated with services provided to Everus.
▪Interest expense was comparable to the same period in the prior year.
•Income tax expense decreased $700,000, largely due to lower income before income taxes.
Nine Months Ended September 30, 2026, Compared to Nine Months Ended September 30, 2025 Pipeline earnings decreased $6.6 million as a result of:
•Revenues increased $200,000 as a result of:
◦Increased demand revenue, largely due to:
▪Increased usage of short-term natural gas transportation contracts of $1.9 million.
▪Growth projects placed in service of $1.2 million.
▪Increased customer demand for long-term natural gas transportation contracts of $1.2 million.
◦Largely offset by:
▪Lower interruptible transportation volumes of $2.0 million.
▪Lower storage-related revenue of $1.6 million.
•Operation and maintenance increased $2.8 million.
◦Primarily from:
▪Higher payroll-related costs of $1.7 million.
▪Higher materials costs of $1.4 million.
▪Higher consulting and legal costs associated with the Company's recent rate case filing.
◦Also reflected is lower costs associated with services provided to Everus as part of the TSA, offset in other income, as described below.
•Depreciation and amortization increased $900,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.
•Taxes, other than income increased $800,000, largely due to higher property tax accruals in Montana.
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Index
•Other income decreased $3.9 million:
◦Largely due to:
▪Advisory costs associated with Bakken East incurred in 2026 that were not eligible for capitalization of $1.6 million.
▪Lower TSA income of $1.2 million, as described above.
▪Lower investment returns on the Company's non-qualified benefit plans of $500,000.
•Interest expense was comparable to the same period in the prior year.
•Income tax expense decreased $1.5 million, largely due to lower income before income taxes.
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.
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 opportunities 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 Administrator's announcement regarding 31 historic actions to advance the President's "Power the Great American Comeback" agenda, which includes extending deadlines for and reconsidering certain oil and gas new source performance standards as well as a proposal to reconsider the Greenhouse Gas Reporting Program. The Company continues to comply with rules as they remain effective, and to monitor and assess these rulemakings 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 on growth opportunities through organic expansion 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 filed its FERC 7(c) application in March 2026. The project is dependent on regulatory approvals and targeted to be in service in late 2028.
•In September 2026, the Company's board of directors made a positive final investment decision to proceed with Bakken East, a proposed pipeline project spanning approximately 350 miles from western to eastern North Dakota, plus additional laterals. The project is estimated to cost $2.8 billion to $3.1 billion and is designed for initial natural gas transportation capacity of 1.4 billion cubic feet per day, with flexibility for future growth. The Company has executed precedent agreements with all customers that submitted binding interest in the March 2026 open season, securing nearly 1.2 billion cubic feet per day of firm capacity. A negotiated option could increase contracted volumes to nearly all of the 1.4 billion cubic feet per day originally requested. Commitments include up to $50 million annually for 10 years from the State of North Dakota. The Company is actively evaluating debt and equity financing structures to fund the project, including potential participation of financial or strategic investors, and expects to retain majority ownership and operational control. Project investment would be incremental to the Company's capital investment plan outlined in the 2025 Annual Report. Engineering, environmental review and pre-filing activities are advancing, with the FERC section 7(c) application anticipated in the fourth quarter of 2026. The Company continues to incur development costs and has contractual and commercial arrangements intended to mitigate its related financial exposure. Phase One is targeted for completion in late 2029 and Phase Two in late 2030, subject to regulatory approvals. For related risks and uncertainties, see Item 1A. Risk Factors in this quarterly report and Part I, Item 1A. Risk Factors in the 2025 Annual Report.
•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 which has been extended through December 2026. The project would provide incremental natural gas transportation capacity for anticipated industrial demand.
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Other
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating revenues | $ | .2 | $ | .3 | $ | .6 | $ | .6 | |||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Operation and maintenance | .3 | (1.5) | 1.0 | (1.0) | |||||||||||||||||||
| Total operating expenses | .3 | (1.5) | 1.0 | (1.0) | |||||||||||||||||||
| Operating (loss) income | (.1) | 1.8 | (.4) | 1.6 | |||||||||||||||||||
| Other income | .6 | 2.0 | 2.3 | 5.0 | |||||||||||||||||||
| Interest expense | .7 | 1.6 | 2.7 | 3.5 | |||||||||||||||||||
| Income (loss) before income taxes | (.2) | 2.2 | (.8) | 3.1 | |||||||||||||||||||
| Income tax expense | 4.6 | 3.9 | 3.0 | 3.5 | |||||||||||||||||||
| Loss from continuing operations | (4.8) | (1.7) | (3.8) | (.4) | |||||||||||||||||||
| Discontinued operations, net of tax | (.1) | — | 1.8 | (.9) | |||||||||||||||||||
| Net loss | $ | (4.9) | $ | (1.7) | $ | (2.0) | $ | (1.3) | |||||||||||||||
Three Months Ended September 30, 2026, Compared to Three Months Ended September 30, 2025
For the third quarter of 2026, Other reported a net loss of $4.9 million, compared to a $1.7 million loss for the same period in 2025. The decrease was primarily due to higher claims experience at the captive insurer and higher income tax expense due to income tax adjustments related to the Company’s annualized estimated tax rate.
Nine Months Ended September 30, 2026, Compared to Nine Months Ended September 30, 2025
Other reported a net loss of $2.0 million for the nine months ended September 30, 2026 compared to a net loss of $1.3 million for the same period in 2025. The decrease was primarily due to higher claims experience at the captive insurer and higher income tax expense due to income tax adjustments related to the Company’s annualized estimated tax rate. The decrease was partially offset by income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs.
Also included in Other is general and administrative costs and interest expense previously allocated to the Company's former businesses that did not meet the criteria for discontinued operations. Discontinued operations includes certain costs associated with legacy business activities.
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:
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| (In millions) | |||||||||||||||||
| Intersegment transactions: | |||||||||||||||||
| Operating revenues | $ | 4.5 | $ | 4.7 | $ | 49.9 | $ | 48.7 | |||||||||
| Purchased natural gas sold | $ | 4.0 | $ | 4.2 | $ | 48.3 | $ | 47.3 | |||||||||
| Operation and maintenance | $ | .5 | $ | .5 | $ | 1.6 | $ | 1.4 | |||||||||
| Other income | $ | .4 | $ | 1.7 | $ | 1.7 | $ | 3.9 | |||||||||
| Interest expense | $ | .4 | $ | 1.7 | $ | 1.7 | $ | 3.9 | |||||||||
For more information on intersegment eliminations, see Note 14.
Liquidity and Capital Commitments
At September 30, 2026, the Company had cash, cash equivalents and restricted cash of $27.6 million and available borrowing capacity of $588.5 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.
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Cash flows
| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2026 | 2025 | |||||||
| (In millions) | ||||||||
| Net cash provided by (used in): | ||||||||
| Operating activities | $ | 347.6 | $ | 392.8 | ||||
| Investing activities | (344.3) | (359.8) | ||||||
| Financing activities | (3.9) | (24.0) | ||||||
| (Decrease) increase in cash, cash equivalents and restricted cash | (.6) | 9.0 | ||||||
| Cash, cash equivalents and restricted cash -- beginning of year | 28.2 | 66.9 | ||||||
Cash, cash equivalents and restricted cash -- end of period | $ | 27.6 | $ | 75.9 | ||||
Operating activities
| Nine Months Ended | ||||||||||||||
| September 30, | ||||||||||||||
| 2026 | 2025 | Variance | ||||||||||||
| (In millions) | ||||||||||||||
| Components of net cash provided by operating activities: | ||||||||||||||
| Net income | $ | 116.1 | $ | 114.1 | $ | 2.0 | ||||||||
| Income (loss) from discontinued operations, net of tax | 1.8 | (0.9) | 2.7 | |||||||||||
| Income from continuing operations | 114.3 | 115.0 | (.7) | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
| Depreciation, depletion and amortization | 165.0 | 155.2 | 9.8 | |||||||||||
| Deferred income taxes | 22.0 | (12.5) | 34.5 | |||||||||||
| Other adjustments | 9.0 | 5.7 | 3.3 | |||||||||||
| Changes in current assets and liabilities, net of acquisitions: | ||||||||||||||
| Receivables | 106.3 | 136.3 | (30.0) | |||||||||||
| Inventories | (3.2) | (.6) | (2.6) | |||||||||||
| Other current assets | (46.8) | 47.6 | (94.4) | |||||||||||
| Accounts payable | (41.9) | (47.7) | 5.8 | |||||||||||
| Other current liabilities | 34.2 | 13.8 | 20.4 | |||||||||||
| Pension & postretirement benefit plan contributions | (3.7) | (2.8) | (.9) | |||||||||||
| Other noncurrent changes | (8.9) | (16.5) | 7.6 | |||||||||||
| Net cash provided by continuing operations | 346.3 | 393.5 | (47.2) | |||||||||||
| Net cash provided by (used in) discontinued operations | 1.3 | (.7) | 2.0 | |||||||||||
| Net cash provided by operating activities | $ | 347.6 | $ | 392.8 | $ | (45.2) | ||||||||
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.
•Net cash provided by continuing operations was $47.2 million lower, primarily attributable to:
◦Other current assets $(94.4) million: due to lower collections of purchased gas costs of $47.2 million, carbon compliance costs of $21.6 million, and decoupling balances of $5.0 million, all at the natural gas distribution business; as well as a $7.5 million decrease in net position for income taxes.
◦Receivables $(30.0) million: due to lower collection of accounts receivable due to warmer than normal weather in December 2025.
◦Partially offset by:
▪Deferred income taxes $34.5 million: which resulted from higher plant related deferrals of $19.0 million, purchased gas cost adjustments of $10.7 million, and environmental compliance deductions of $3.3 million.
▪Other current liabilities $20.4 million: due to higher electric fuel balances owed to customers of $11.2 million and large load customer deposit of $9.2 million.
▪Other noncurrent changes $7.6 million: due to 2025 preliminary project costs.
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Index
Investing activities
| Nine Months Ended | ||||||||||||||
| September 30, | ||||||||||||||
| 2026 | 2025 | Variance | ||||||||||||
| (In millions) | ||||||||||||||
| Components of net cash used in investing activities: | ||||||||||||||
| Capital expenditures | $ | (332.1) | $ | (353.8) | $ | 21.7 | ||||||||
| Cost of removal, net | (13.0) | (7.7) | (5.3) | |||||||||||
| Purchase of investment securities | (3.2) | (3.3) | .1 | |||||||||||
Proceeds from investment securities | 4.0 | 5.0 | (1.0) | |||||||||||
| Net cash used in investing activities | $ | (344.3) | $ | (359.8) | $ | 15.5 | ||||||||
•Net cash used in investing activities was $15.5 million lower, primarily attributable to:
◦Capital expenditures $21.7 million: due to lower electric wind project expenditures of $57.5 million, partially offset by higher natural gas distribution expenditures of $29.0 million and higher expenditures of $7.1 million at the pipeline segment.
Financing activities
| Nine Months Ended | ||||||||||||||
| September 30, | ||||||||||||||
| 2026 | 2025 | Variance | ||||||||||||
| (In millions) | ||||||||||||||
| Components of net cash used in financing activities: | ||||||||||||||
| Issuance of long-term debt | $ | 497.2 | $ | 123.1 | $ | 374.1 | ||||||||
| Repayment of long-term debt | (577.3) | (62.8) | (514.5) | |||||||||||
| Debt issuance costs | (2.6) | (.2) | (2.4) | |||||||||||
Issuance of common stock, net | 170.0 | — | 170.0 | |||||||||||
| Dividends paid | (86.7) | (79.6) | (7.1) | |||||||||||
| Tax withholding on stock-based compensation | (4.5) | (4.5) | — | |||||||||||
| Net cash used in financing activities | $ | (3.9) | $ | (24.0) | $ | 20.1 | ||||||||
•Net cash used in financing activities was $20.1 million lower, primarily attributable to:
◦Issuance of long-term debt $374.1 million: $485.0 million of senior notes were issued in 2026 under a NPA, partially offset by lower credit agreement issuances of $78.1 million and absence of a 2025 debt issuance of $25.0 million.
◦Issuance of common stock $170.0 million: of which $88.9 million was net issuances under the Company's ATM program and $81.3 million was cash received from partial settlement under the Company's FSA.
◦Partially offset by:
▪Repayment of long-term debt $(514.5) million: due to increased repayments of $390.0 million primarily at Montana-Dakota and higher credit agreement repayments of $149.5 million.
▪Dividends paid $(7.1) million: higher dividends paid in 2026 due to an increase in the dividends declared per common share and an increase in the number of average common shares outstanding.
Capital expenditures
Capital expenditures for the first nine months of 2026 and 2025 were $373.7 million and $379.5 million, respectively. Capital expenditures at the Company's business segments are estimated to be approximately $594.4 million for 2026, which is a slight increase to what was previously reported in the 2025 Annual Report. The increase is primarily driven by increased pipeline investments associated with the Bakken East final investment decision reached on September 30, 2026, partially offset by lower electric and natural gas distribution investments due to the timing of JETx capital expenditures and the decision to discontinue development of the Knott Landfill RNG project, respectively. Investment in Bakken East remains incremental to the capital plan outlined in the 2025 Annual Report. Capital expenditure estimates have been updated to accommodate project timeline and scope changes made thus far in 2026.
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.
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Index
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 estimate previously discussed. The Company continuously monitors its capital expenditures for project delays and changes in economic viability and adjusts as necessary. It is anticipated that all 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.
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 instruments, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions. The Company and its subsidiaries were in compliance with applicable covenants at September 30, 2026. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. As of September 30, 2026, the Company had investment grade credit ratings at all entities issuing debt. For more information on the Company's debt instruments, covenants, certain other conditions and cross-default provisions, see Note 13 and Part II, Item 6 in this document and Part II, Item 8 in the 2025 Annual Report.
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 enter into any FSAs related to the EDA. As of September 30, 2026, the Company had capacity to issue up to an aggregate gross sales price of $310.0 million in shares of common stock under the ATM offering program.
On December 5, 2025, the Company completed a follow-on public offering of 10.2 million 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 1.5 million additional shares of the Company's common stock. Pursuant to the FSAs entered into in connection with the offering, the Company has the 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.
In March 2026, the Company partially settled the FSAs with physical delivery of 4.3 million shares of common stock to the counterparties in exchange for cash of $81.3 million. At September 30, 2026, the Company could have settled all of its outstanding FSAs with physical delivery of 7.4 million shares of common stock to the banking counterparties in exchange for cash of approximately $139.6 million. If the FSAs had been net cash or net share settled at September 30, 2026, the Company, in aggregate, would have been entitled to a net settlement of approximately $2.8 million or 153,231 shares, respectively.
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 were and 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 Note 8.
Material cash requirements
There were no material changes in the Company's remaining contractual obligations related to asset retirement obligations and uncertain tax positions for 2026 from those reported in the 2025 Annual Report. As of September 30, 2026, estimated interest payments increased compared with those reported in the 2025 Annual Report primarily due to debt issuances in the third quarter of 2026. For more information on newly issued debt, see Note 13 in this document. For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Part II, Item 7 in the 2025 Annual Report.
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.
50
Index
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.
Defined benefit pension plans
The Company has noncontributory qualified defined benefit pension plans for certain employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans, as such costs of providing these benefits bear the risk of changes as they are dependent upon assumptions of future conditions.
There were no material changes to the Company's noncontributory qualified defined benefit pension plans from those reported in the 2025 Annual Report other than the Company contributed approximately $3.7 million to its pension plans in 2026. For more information, see Note 15 and Part II, Item 7 in the 2025 Annual Report.
New Accounting Standards
For information regarding new accounting standards, see Note 2, which is incorporated by reference.
Critical Accounting Estimates
The Company's critical accounting estimates include impairment testing of goodwill; regulatory assets expected to be recovered in rates charged to customers; actuarially determined pension and other postretirement benefit costs; and income taxes. There were no material changes in the Company's critical accounting estimates from those reported in the 2025 Annual Report. For more information on critical accounting estimates, see Part II, Item 7 in the 2025 Annual Report.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
There were no material changes to the Company's market risks in Part II, Item 7A - Quantitative and Qualitative Disclosures About Market Risk in the 2025 Annual Report.
Item 4. Controls and Procedures
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 September 30, 2026, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.
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Index
Part II -- Other Information
Item 1. Legal Proceedings
There were no material changes to the Company's legal proceedings in Part I, Item 3 - Legal Proceedings in the 2025 Annual Report.
Item 1A. Risk Factors
Please refer to the Company's risk factors that are disclosed in Part I, Item 1A. Risk Factors in the 2025 Annual Report that could be materially harmful to the Company's business, prospects, financial condition or financial results if they occur. At September 30, 2026, there were no material changes to the Company's risk factors provided in Part I, Item 1A. Risk Factors in the 2025 Annual Report other than as set forth below.
The proposed Bakken East pipeline project involves substantial capital investment and is subject to numerous risks and uncertainties that could materially adversely affect the Company’s business, financial condition, results of operations, and cash flows.
On September 30, 2026, the Company’s board of directors approved a final investment decision to proceed with the proposed Bakken East pipeline project through the Company’s pipeline business, WBI Energy Transmission. Bakken East is expected to include approximately 350 miles of pipeline and provide approximately 1.4 billion cubic feet per day of natural gas transportation capacity. Bakken East is expected to be constructed in two phases, targeted for completion in late 2029 and late 2030. The estimated aggregate cost is approximately $2.8 billion to $3.1 billion, none of which amount is currently included in the Company’s capital plan outlined in the 2025 Annual Report. Bakken East is subject to numerous risks and uncertainties, many of which are beyond the Company’s control. These include:
•Project costs and execution. Actual costs and construction timelines could differ materially from current estimates due to inflation, tariffs, changes in materials and labor costs, labor shortages, equipment availability, supply chain disruptions, contractor performance, adverse weather, unforeseen site or environmental conditions, changes in project scope or design, permitting or regulatory requirements, including environmental requirements, and other factors. Cost increases or delays could adversely affect project returns, our financial condition and credit ratings, and our ability to fund other capital projects or pay dividends.
•Financing and partnership arrangements. The Company has not yet secured definitive project financing or one or more project partners. The Company's ability to obtain financing or secure suitable partners on acceptable terms may be affected by capital-market conditions, interest rates, investor interest and other factors. Any partnership arrangement could also require the Company to share economic returns, control, and/or decision-making authority.
•Regulatory approvals. Bakken East requires federal, state, and local regulatory approvals and permits, which may not be received on the anticipated terms or timeline and could result in delays, additional costs or changes to the project.
•Project economics and commercial commitments. Although the Company has entered into precedent agreements representing nearly 1.2 billion cubic feet per day of firm natural gas transportation capacity, the precedent agreements are subject to conditions precedent. The loss of one or more customers, or their failure to fulfill contractual commitments, could adversely affect project revenues and expected financial returns.The Bakken East project economics also depend on continued natural gas production and demand for natural gas transportation capacity in the Bakken region. Changes in commodity prices, competing pipeline capacity, energy policy or customer circumstances could adversely affect utilization and expected financial returns.
•Other project and operating risks. Bakken East may not operate as expected or achieve anticipated financial returns due to operating disruptions, equipment failures, severe weather, cybersecurity incidents, third-party damage or other events. The Company has also incurred, and expects to continue to incur, significant development costs, including engineering, environmental, legal, regulatory, land acquisition and advisory expenses, some of which may not be recoverable if Bakken East is delayed, modified or not completed as currently contemplated.
Any of these risks could cause Bakken East to be delayed, cost more than anticipated, fail to achieve expected financial returns or not be completed as currently contemplated, which could materially adversely affect the Company's business, financial condition, results of operations and cash flows.
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Index
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
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) | ||||||||||
| July 1 through July 31, 2026 | — | $ | — | — | — | |||||||||
| August 1 through August 31, 2026 | — | — | — | — | ||||||||||
| September 1 through September 30, 2026 | 1,634 | 18.81 | — | — | ||||||||||
| Total | 1,634 | $ | 18.81 | — | — | |||||||||
(1) Represents shares of common stock purchased on the open market for the Company's non-employee directors who elected to receive additional shares of common stock in lieu of a portion of their cash retainer. (2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to repurchase equity securities. | ||
Item 5. Other Information
During the three months ended September 30, 2026, no director or officer of the Company adopted terminated
Item 6. Exhibits
See the index to exhibits immediately preceding the signature page to this report.
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Index
| Exhibits Index | |||||||||||||||||||||||
| Incorporated by Reference | |||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Filed Herewith | Form | Period Ended | Exhibit | Filing Date | File Number | ||||||||||||||||
| 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) | Montana-Dakota Utilities Co. Note Purchase Agreement, Dated June 16, 2026 | X | |||||||||||||||||||||
| **4(b) | Cascade Natural Gas Corporation Note Purchase Agreement, dated August 24, 2026 | X | |||||||||||||||||||||
| **4(c) | Intermountain Gas Company Note Purchase Agreement, dated September 22, 2026 | X | |||||||||||||||||||||
| ***10(a) | Forward Sale Agreement between MDU Resources Group, Inc. and Wells Fargo Bank, National Association, dated August 27, 2026 | X | |||||||||||||||||||||
| ***10(b) | Forward Sale Agreement between MDU Resources Group, Inc. and Bank of America, N.A., dated September 2, 2026 | X | |||||||||||||||||||||
| ***10(c) | Forward Sale Agreement between MDU Resources Group, Inc. and JPMorgan Chase Bank, National Association, New York Branch, dated September 4, 2026 | 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 | |||||||||||||||||||||
| 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) | ||||||||||||||||||||||
*Furnished Herewith | ||
**Certain schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to supplementally furnish copies of any omitted schedules and exhibits to the U.S. Securities and Exchange Commission upon request; provided that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended. | ||
***Certain portions of this exhibit have been redacted pursuant to Item 301(b)(10)(iv) of Regulations S-K. The Company hereby undertakes to supplementally furnish an unredacted copy of the exhibit to the Securities and Exchange Commission upon its request. | ||
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Signatures
Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| MDU RESOURCES GROUP, INC. | |||||||||||
| DATE: | November 5, 2026 | BY: | /s/ Jason L. Vollmer | ||||||||
| Jason L. Vollmer | |||||||||||
| Chief Financial Officer | |||||||||||
| BY: | /s/ Stephanie A. Sievert | ||||||||||
| Stephanie A. Sievert | |||||||||||
| Chief Accounting and Regulatory Affairs Officer | |||||||||||
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