Companies: 11,222     total market cap: $155.242 T
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MDU Resources
MDU
#3538
Rank
$4.32 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$20.55
Share price
-1.01%
Change (1 day)
24.77%
Change (1 year)
  1. MDU Resources
  2. Quarterly Reports (10-Q)
  3. Financial Year FY2026 Q2

MDU Resources - 10-Q quarterly report FY2026 Q2


Text size:
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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 June 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
MDU RESOURCES GROUP, INC.
(Exact name of registrant as specified in its charter)
Delaware30-1133956
(State or other jurisdiction of
incorporation or organization)		(I.R.S. Employer Identification No.)
1200 West Century Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 530-1000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbol(s)Name of each exchange on which registered
Common Stock, par value $1.00 per shareMDUNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
☒
Accelerated Filer
☐
Non-Accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant 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 July 30, 2026: 210,349,456 shares.
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Page
3
5
Part I -- Financial Information
Item 1. Financial Statements
6
Consolidated Statements of Income -- Three and Six Months Ended June 30, 2026 and 2025
6
Consolidated Statements of Comprehensive Income -- Three and Six Months Ended June 30, 2026 and 2025
7
Consolidated Balance Sheets -- June 30, 2026 and 2025, and December 31, 2025
8
Consolidated Statements of Equity -- Six Months Ended June 30, 2026 and 2025
9
Consolidated Statements of Cash Flows -- Six Months Ended June 30, 2026 and 2025
10
Condensed Notes to Consolidated Financial Statements
11
1. Basis of presentation
11
2. New accounting standards
11
3. Discontinued operations
12
4. Seasonality of operations
12
5. Receivables and allowance for expected credit losses
12
6. Inventories and natural gas in storage
13
7. Earnings per share
14
8. Equity
14
9. Revenue from contracts with customers
15
10. Regulatory matters
17
11. Environmental allowances and obligations
20
12. Fair value measurements
20
13. Debt
23
14. Business segment data
25
15. Employee benefit plans
29
16. Commitments and contingencies
30
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
32
Item 3. Quantitative and Qualitative Disclosures About Market Risk
49
Item 4. Controls and Procedures
49
Item 1. Legal Proceedings
50
Item 1A. Risk Factors
50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
50
Item 5. Other Information
50
Item 6. Exhibits
50
51
52

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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
AFUDCAllowance for funds used during construction
Applied DigitalApplied Digital Corporation
ASCFASB Accounting Standards Codification
ASUFASB Accounting Standards Update
ATM
At-the-Market
Badger Wind Farm
250 MW wind turbine farm near Wishek, North Dakota (49.0 percent ownership)
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
CascadeCascade Natural Gas Corporation, an indirect wholly-owned subsidiary of MDU Energy Capital
CentennialCEHI, 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 CapitalCentennial Holdings Capital LLC, a direct wholly-owned subsidiary of Centennial
CODMChief Operating Decision Maker
CompanyMDU Resources Group, Inc.
COVID-19Coronavirus disease 2019
Coyote CreekCoyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
CPP
Climate Protection Program
CWIPConstruction work in progress, costs associated with the construction of new utility facilities recorded on the balance sheet until these facilities are placed in service
dkDecatherm
EDA
Equity Distribution Agreement
Eighth Circuit
United States Court of Appeals for the Eighth Circuit
EPAUnited 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 ConstructionEverus 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 ActSecurities Exchange Act of 1934, as amended
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FSA
Forward sale agreement
GAAPAccounting principles generally accepted in the United States of America
GHGGreenhouse gas
Holding Company ReorganizationThe 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
HPCHigh performance computing
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IntermountainIntermountain Gas Company, an indirect wholly-owned subsidiary of MDU Energy Capital
JETx345-kV transmission line from Jamestown, North Dakota to Ellendale, North Dakota (50 percent ownership)
kWhKilowatt-hour
kVKilovolt
MDU Energy CapitalMDU Energy Capital, LLC, a direct wholly-owned subsidiary of the Company
MDUR NewcoMDUR Newco, Inc., a public holding company created by implementing the Holding Company Reorganization, now known as the Company
MDUR Newco SubMDUR Newco Sub, Inc., a direct, wholly-owned subsidiary of MDUR Newco, which was merged with and into Montana-Dakota in the Holding Company Reorganization
MISOMidcontinent 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
MMcfMillion cubic feet
MMdkMillion dk
Montana-DakotaMontana-Dakota Utilities Co., a direct wholly-owned subsidiary of MDU Energy Capital
MWMegawatt
NDDEQNorth Dakota Department of Environmental Quality
NDPSCNorth Dakota Public Service Commission
NERCNorth 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
ODEQOregon Department of Environmental Quality
OEQC
Oregon Environmental Quality Commission
PHMSAPipeline 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
RNGRenewable natural gas
SBCCState Building Code Council
SDPUCSouth Dakota Public Utilities Commission
SOFR
Secured Overnight Financing Rate
SECUnited 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
VIEVariable interest entity
WBI Energy WBI Energy, Inc., an indirect wholly-owned subsidiary of Centennial
WBI Energy TransmissionWBI Energy Transmission, Inc., an indirect wholly-owned subsidiary of Centennial
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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.
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Part I -- Financial Information
Item 1. Financial Statements
MDU Resources Group, Inc.
Consolidated Statements of Income
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands, except per share amounts)
Operating revenues $375,303 $351,186 $981,280 $1,026,019 
Operating expenses:
Purchased natural gas sold93,538 96,057 332,929 413,214 
Electric fuel and purchased power38,674 34,891 84,741 78,639 
Operation and maintenance114,016 112,887 228,921 223,934 
Depreciation and amortization55,183 51,853 109,362 103,114 
Taxes, other than income25,947 25,166 61,677 63,923 
Total operating expenses327,358 320,854 817,630 882,824 
Operating income47,945 30,332 163,650 143,195 
Other income6,227 9,945 8,832 14,942 
Interest expense31,548 25,445 64,233 52,267 
Income before income taxes22,624 14,832 108,249 105,870 
Income taxes3,351 655 8,029 9,226 
Income from continuing operations19,273 14,177 100,220 96,644 
Discontinued operations, net of tax1,967 (397)1,837 (899)
Net income$21,240 $13,780 $102,057 $95,745 
Earnings per share - basic:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - basic$.10 $.07 $.49 $.47 
Earnings per share - diluted:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - diluted$.10 $.07 $.49 $.47 
Weighted average common shares outstanding - basic209,630 204,331 207,545 204,237 
Weighted average common shares outstanding - diluted211,663 205,211 209,342 205,086 
The accompanying condensed notes are an integral part of these consolidated financial statements.
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MDU Resources Group, Inc.
Consolidated Statements of Comprehensive Income
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands)
Net income$21,240 $13,780 $102,057 $95,745 
Other comprehensive income:
Postretirement liability adjustment:
Amortization of postretirement liability losses included in net periodic benefit credit, net of tax of $50 and $33 for the three months ended and $85 and $51 for the six months ended in 2026 and 2025, respectively
159 103 333 221 
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 $(10) and $4 for the three months ended and $(20) and $23 for the six months ended in 2026 and 2025, respectively
(39)14 (76)85 
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $1 and $1 for the three months ended and $2 and $1 for the six months ended in 2026 and 2025, respectively
3 3 6 6 
Net unrealized (loss) gain on available-for-sale investments(36)17 (70)91 
Other comprehensive income123 120 263 312 
Comprehensive income attributable to common stockholders$21,363 $13,900 $102,320 $96,057 
The accompanying condensed notes are an integral part of these consolidated financial statements.
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MDU Resources Group, Inc.
Consolidated Balance Sheets
(Unaudited)
June 30, 2026June 30, 2025December 31, 2025
Assets(In thousands, except shares and per share amounts)
Current assets:
Cash, cash equivalents and restricted cash$46,269 $58,801 $28,212 
Receivables, net151,694 156,728 258,631 
Current regulatory assets192,794 141,744 179,579 
Inventories19,330 19,713 39,052 
Current environmental allowances24,242 20,449 26,194 
Prepayments and other current assets61,646 44,491 40,768 
Total current assets495,975 441,926 572,436 
Noncurrent assets:
Property, plant and equipment8,408,615 7,711,004 8,264,972 
Less accumulated depreciation and amortization2,351,592 2,276,447 2,304,787 
Net property, plant and equipment6,057,023 5,434,557 5,960,185 
Goodwill345,736 345,736 345,736 
Regulatory assets295,865 309,302 297,218 
Investments123,137 115,784 121,177 
Environmental allowances162,151 111,671 112,376 
Other232,187 186,941 213,078 
Total noncurrent assets 7,216,099 6,503,991 7,049,770 
Total assets$7,712,074 $6,945,917 $7,622,206 
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year$4,700 $136,700 $144,700 
Accounts payable110,742 107,178 148,970 
Regulatory liabilities due within one year156,951 134,254 148,584 
Taxes payable34,359 53,428 44,686 
Dividends payable29,449 26,563 28,614 
Accrued compensation21,409 20,795 34,666 
Current environmental obligations24,086 19,561 24,086 
Other accrued liabilities118,035 96,312 110,917 
Total current liabilities 499,731 594,791 685,223 
Noncurrent liabilities:
Long-term debt2,572,457 2,045,235 2,532,155 
Deferred income taxes454,147 426,556 437,286 
Regulatory liabilities478,405 468,168 472,329 
Asset retirement obligations441,048 415,137 431,587 
Environmental obligations153,741 93,451 108,448 
Other185,623 170,675 182,261 
Total noncurrent liabilities 4,285,421 3,619,222 4,164,066 
Commitments and contingencies
Stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 210,349,456 at June 30, 2026, 204,331,170 at
June 30, 2025 and 204,382,821 at December 31, 2025
210,349 204,331 204,383 
Other paid-in capital1,580,599 1,472,150 1,476,355 
Retained earnings1,152,426 1,071,909 1,108,894 
Accumulated other comprehensive loss(16,452)(16,486)(16,715)
Total stockholders' equity2,926,922 2,731,904 2,772,917 
Total liabilities and stockholders' equity $7,712,074 $6,945,917 $7,622,206 
The accompanying condensed notes are an integral part of these consolidated financial statements.
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MDU Resources Group, Inc.
Consolidated Statements of Equity
(Unaudited)
Other
Paid-in
Capital		Retained Earnings
Accumulated
Other
Comprehensive
Loss
Common Stock
SharesAmountTotal
(In thousands, except shares)
At December 31, 2025
204,382,821 $204,383 $1,476,355 $1,108,894 $(16,715)$2,772,917 
Net income — — — 80,817 — 80,817 
Other comprehensive income— — — — 140 140 
Dividends declared on common stock— — — (28,868)— (28,868)
Stock-based compensation— — 1,932 — — 1,932 
Issuance of common stock, net
4,300,000 4,300 76,859 — — 81,159 
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings323,203 323 (4,782)— — (4,459)
At March 31, 2026209,006,024 $209,006 $1,550,364 $1,160,843 $(16,575)$2,903,638 
Net income — — — 21,240 — 21,240 
Other comprehensive income— — — — 123 123 
Dividends declared on common stock— — — (29,657)— (29,657)
Stock-based compensation— — 1,934 — — 1,934 
Issuance of common stock, net1,343,432 1,343 28,301 — — 29,644 
At June 30, 2026210,349,456 $210,349 $1,580,599 $1,152,426 $(16,452)$2,926,922 

Other
Paid-in
Capital		Retained Earnings
Accumulated
Other
Comprehensive
Loss
Common Stock
SharesAmountTotal
(In thousands, except shares)
At December 31, 2024
203,934,578 $203,935 $1,473,738 $1,029,699 $(16,798)$2,690,574 
Net income — — — 81,965 — 81,965 
Other comprehensive income— — — — 192 192 
Dividends declared on common stock— — — (26,765)— (26,765)
Stock-based compensation— — 1,646 — — 1,646 
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings396,592 396 (4,872)— — (4,476)
At March 31, 2025204,331,170 $204,331 $1,470,512 $1,084,899 $(16,606)$2,743,136 
Net income — — — 13,780 — 13,780 
Other comprehensive income— — — — 120 120 
Dividends declared on common stock— — — (26,770)— (26,770)
Stock-based compensation— — 1,638 — — 1,638 
At June 30, 2025204,331,170 $204,331 $1,472,150 $1,071,909 $(16,486)$2,731,904 
The accompanying condensed notes are an integral part of these consolidated financial statements.
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MDU Resources Group, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
Six Months Ended
June 30,
20262025
(In thousands)
Operating activities:
Net income$102,057 $95,745 
Income (loss) from discontinued operations, net of tax1,837 (899)
Income from continuing operations100,220 96,644 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization109,362 103,114 
Deferred income taxes11,636 (19,003)
Provision for credit losses3,110 3,179 
Amortization of debt issuance costs878 619 
Employee stock-based compensation costs3,866 3,284 
Pension and postretirement benefit plan net periodic benefit cost (credit)696 (534)
Unrealized gains on investments(4,062)(2,557)
Changes in current assets and liabilities, net of acquisitions:
Receivables103,827 129,471 
Inventories19,306 24,957 
Other current assets(22,982)86,740 
Accounts payable(36,375)(47,580)
Other current liabilities(7,678)(28,493)
Pension and postretirement benefit plan contributions(960)(2,465)
Other noncurrent changes(16,888)(11,790)
Net cash provided by continuing operations263,956 335,586 
Net cash provided by (used in) discontinued operations1,344 (702)
Net cash provided by operating activities265,300 334,884 
Investing activities:
Capital expenditures(193,500)(173,982)
Cost of removal, net(3,894)(2,577)
Purchase of investment securities
(2,743)(2,858)
Proceeds from investment securities
4,000 5,000 
Net cash used in investing activities(196,137)(174,417)
Financing activities:
Issuance of long-term debt134,450 — 
Repayment of long-term debt(234,009)(111,008)
Debt issuance costs(619)(11)
Issuance of common stock, net
110,803 — 
Dividends paid(57,272)(53,075)
Tax withholding on stock-based compensation(4,459)(4,476)
Net cash used in financing activities(51,106)(168,570)
Increase (decrease) in cash, cash equivalents and restricted cash18,057 (8,103)
Cash, cash equivalents and restricted cash - beginning of year28,212 66,904 
Cash, cash equivalents and restricted cash - end of period
$46,269 $58,801 
Supplemental cash flow information:
Cash expenditures during the year for:
Interest, net*
$57,289 $49,407 
Income taxes paid, net$1,578 $6,225 
Noncash investing and financing transactions:
Property, plant and equipment additions in accounts payable
$41,295 $38,644 
Right-of-use assets obtained in exchange for new operating lease liabilities
$359 $500 
*AFUDC - borrowed was $4.1 million and $3.4 million for the six months ended June 30, 2026 and 2025, respectively.
The accompanying condensed notes are an integral part of these consolidated financial statements.
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MDU Resources Group, Inc.
Condensed Notes to Consolidated
Financial Statements
June 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.
Management has also evaluated the impact of events occurring after June 30, 2026, up to the date of issuance of these consolidated interim financial statements on August 6, 2026, that would require recognition or disclosure in the Consolidated Financial Statements.
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:
StandardDescriptionEffective dateImpact 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 ObligationsIn 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.
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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. For the three and six months ended June 30, 2026, the Company received $72,000 and $1.3 million, respectively, for these related activities. For the three and six months ended June 30, 2025, the Company received $3.7 million and $5.5 million, respectively, and paid $12,000 and $25,000, respectively, for these related activities. All transition services were completed as of March 31, 2026.
The Company did not incur any separation related costs for the three months ended June 30, 2026. Separation related costs of $130,000, net of tax, were incurred during the six months ended June 30, 2026 and $45,000 and $547,000, net of tax, for the three and six months ended June 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.
The Company had no assets or liabilities related to the discontinued operations of Everus on its balance sheet as of June 30, 2026, June 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 EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands)
Operating revenues$1 $— $1 $— 
Operating expenses(650)429 (494)1,028 
Operating (loss) income651 (429)495 (1,028)
Other income— — — — 
Interest expense— — — — 
Income (loss) from discontinued operations before income taxes651 (429)496 (1,028)
Income tax benefit
(1,316)(32)(1,341)(129)
Discontinued operations, net of tax$1,967 $(397)$1,837 $(899)
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.
The Company's expected credit losses are determined through a review using historical credit loss experience, changes in asset specific characteristics, current conditions and reasonable and supportable future forecasts, among other specific account data, and is performed at least quarterly. The Company develops and documents its methodology to determine its allowance for expected credit losses at each of its reportable business segments. Risk characteristics used by the business segments may include customer mix, knowledge of customers and general economic conditions of the various local economies, among others. Specific account balances are written off when management determines the amounts to be uncollectible. Management has reviewed the balance reserved through the allowance for expected credit losses and believes it is reasonable.
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Index
Details of the Company's expected credit losses were as follows:
ElectricNatural gas
distribution		PipelineTotal
(In thousands)
At December 31, 2025
$506 $1,443 $— $1,949 
Current expected credit loss provision952 1,670 — 2,622 
Less write-offs charged against the allowance1,066 1,098 — 2,164 
Credit loss recoveries collected188 272 — 460 
At March 31, 2026$580 $2,287 $— $2,867 
Current expected credit loss provision269 219 — 488 
Less write-offs charged against the allowance368 1,013 — 1,381 
Credit loss recoveries collected88 167 — 255 
At June 30, 2026$569 $1,660 $— $2,229 
ElectricNatural gas
distribution		PipelineTotal
(In thousands)
At December 31, 2024
$473 $1,366 $— $1,839 
Current expected credit loss provision939 2,213 — 3,152 
Less write-offs charged against the allowance1,036 1,269 — 2,305 
Credit loss recoveries collected166 252 — 418 
At March 31, 2025$542 $2,562 $— $3,104 
Current expected credit loss provision178 (151)— 27 
Less write-offs charged against the allowance333 1,002 — 1,335 
Credit loss recoveries collected74 165 — 239 
At June 30, 2025$461 $1,574 $— $2,035 
Note 6 - Inventories and natural gas in storage
Natural gas in storage is generally valued at lower of cost or market using the last-in, first-out method or lower of cost or net realizable value using the average cost or first-in, first-out method. The majority of all other inventories are valued at the lower of cost or net realizable value using the average cost method. The portion of the cost of natural gas in storage expected to be used within 12 months was included in inventories. Inventories on the Consolidated Balance Sheets were as follows:
June 30, 2026June 30, 2025December 31, 2025
(In thousands)
Natural gas in storage (current)$14,413 $14,937 $34,333 
Fuel stock4,917 4,776 4,719 
Total$19,330 $19,713 $39,052 
The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in noncurrent assets - other and was $47.8 million, $48.5 million and $47.8 million at June 30, 2026 and 2025 and December 31, 2025, respectively.
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Index
Note 7 - Earnings per share
Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per share is computed by dividing net income by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of non-vested performance share awards and restricted stock units, as well as potentially issuable shares pursuant to FSAs using the treasury stock method. Net income was the same for both the basic and diluted earnings per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings per share calculations follows:
Three Months EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands, except per share amounts)
Weighted average common shares outstanding - basic209,630 204,331 207,545 204,237 
Effect of dilutive performance share awards and restricted stock units2,033 880 1,797 849 
Weighted average common shares outstanding - diluted211,663 205,211 209,342 205,086 
Earnings per share - basic:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - basic$.10 $.07 $.49 $.47 
Earnings per share - diluted:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - diluted$.10 $.07 $.49 $.47 
Shares excluded from the calculation of diluted earnings per share— — 25 — 
Dividends declared per common share$.14 $.13 $.28 $.26 
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 June 30, 2026, the Company had capacity to issue up to an aggregate gross sales price of $370.0 million in shares of common stock under the ATM offering program. Details of the Company's ATM offering activity were as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands)
Shares issued1,343 — 1,343 — 
Net proceeds$29,644 $— $29,644 $— 
Issuance costs$356 $— $356 $— 

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 June 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 June 30, 2026, the Company estimates that the counterparties, in aggregate, would have been entitled to a net settlement of $16.8 million or 792,557 shares, respectively.
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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.
The Company recognizes revenue from the sale of emissions allowances allocated under the environmental programs in certain states. The Company has the right to payment when the allowances are sold at auction. Revenue is recognized on a point in time basis within the quarter that the auction is held. The revenues associated with the sale of these allowances are deferred as a component of the respective jurisdiction’s regulatory liability for environmental compliance. For more information on the Company’s regulatory assets and liabilities, see Note 10.
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 June 30, 2026ElectricNatural gas
distribution		PipelineOtherTotal
(In thousands)
Residential utility sales$35,080 $106,001 $— $— $141,081 
Commercial utility sales*
50,479 66,432 — — 116,911 
Industrial utility sales10,946 8,593 — — 19,539 
Other utility sales2,083 — — — 2,083 
Natural gas transportation— 16,834 47,173 — 64,007 
Natural gas storage— — 5,530 — 5,530 
Other18,600 11,371 4,061 201 34,233 
Intersegment eliminations(124)(86)(10,052)(201)(10,463)
Revenues from contracts with customers117,064 209,145 46,712 — 372,921 
Other revenues(1,148)3,502 28 — 2,382 
Total external operating revenues$115,916 $212,647 $46,740 $— $375,303 
*Commercial utility sales includes the impact from data centers at the electric segment.
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Index
Three Months Ended June 30, 2025ElectricNatural gas
distribution		PipelineOtherTotal
(In thousands)
Residential utility sales$28,569 $100,041 $— $— $128,610 
Commercial utility sales*43,428 65,699 — — 109,127 
Industrial utility sales9,247 9,098 — — 18,345 
Other utility sales1,793 — — — 1,793 
Natural gas transportation— 15,814 46,120 — 61,934 
Natural gas storage— — 5,172 — 5,172 
Other17,123 11,626 4,977 179 33,905 
Intersegment eliminations(140)(92)(9,796)(180)(10,208)
Revenues from contracts with customers100,020 202,186 46,473 (1)348,678 
Other revenues(2,134)4,608 34 — 2,508 
Total external operating revenues$97,886 $206,794 $46,507 $(1)$351,186 
*Commercial utility sales includes the impact from data centers at the electric segment.
Six Months Ended June 30, 2026ElectricNatural gas
distribution		PipelineOtherTotal
(In thousands)
Residential utility sales$74,481 $352,327 $— $— $426,808 
Commercial utility sales*99,663 223,800 — — 323,463 
Industrial utility sales20,956 21,005 — — 41,961 
Other utility sales4,043 — — — 4,043 
Natural gas transportation— 34,340 96,250 — 130,590 
Natural gas storage— — 10,997 — 10,997 
Other40,864 31,921 6,565 400 79,750 
Intersegment eliminations(291)(175)(44,512)(400)(45,378)
Revenues from contracts with customers239,716 663,218 69,300 — 972,234 
Other revenues
(2,782)11,776 52 — 9,046 
Total external operating revenues$236,934 $674,994 $69,352 $— $981,280 
*Commercial utility sales includes the impact from data centers at the electric segment.
Six Months Ended June 30, 2025ElectricNatural gas
distribution		PipelineOtherTotal
(In thousands)
Residential utility sales$68,254 $389,276 $— $— $457,530 
Commercial utility sales*91,905 258,030 — — 349,935 
Industrial utility sales18,411 24,560 — — 42,971 
Other utility sales3,643 — — — 3,643 
Natural gas transportation— 33,524 95,373 — 128,897 
Natural gas storage— — 11,202 — 11,202 
Other34,714 35,103 6,339 358 76,514 
Intersegment eliminations(318)(187)(43,132)(358)(43,995)
Revenues from contracts with customers216,609 740,306 69,782 — 1,026,697 
Other revenues(6,462)5,735 49 — (678)
Total external operating revenues$210,147 $746,041 $69,831 $— $1,026,019 
*Commercial utility sales includes the impact from data centers at the electric segment.
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Remaining performance obligations
The remaining performance obligations at the pipeline segment include firm transportation and storage contracts with fixed pricing and fixed volumes. The Company has applied the practical expedient that does not require additional disclosures for contracts with an original duration of less than 12 months, to certain firm transportation, 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 four years and two years, respectively.
At June 30, 2026, the Company expects to recognize revenue in future periods from remaining performance obligations, as follows:
12 months or lessNext 13-24 months25 months or moreTotal
(In millions)
$83.8 $77.7 $329.9 $491.4 
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
June 30, 2026
*June 30, 2026June 30, 2025December 31, 2025
(In thousands)
Regulatory assets:
Current:
Environmental compliance programs
Up to 1 year
$95,915 $63,245 $78,784 
Conservation programs
Up to 1 year
33,426 21,541 29,148 
Decoupling mechanisms
Up to 1 year
23,272 7,974 17,091 
Cost recovery mechanisms
Up to 1 year
18,376 6,389 13,460 
Natural gas costs recoverable through rate adjustments
Up to 1 year
11,334 36,567 22,897 
Electric fuel and purchased power deferral
Up to 1 year
2,043 2,050 6,902 
Other
Up to 1 year
8,428 3,978 11,297 
192,794 141,744 179,579 
Noncurrent:
Pension and postretirement benefits**135,222 142,064 135,222 
Cost recovery mechanisms
Up to 23 years
58,977 70,533 63,328 
Plant costs/asset retirement obligationsOver plant lives48,088 46,684 48,352 
Manufactured gas plant site remediation-28,042 27,212 28,411 
Taxes recoverable from customersOver plant lives12,101 12,220 12,250 
Covid-19 deferred costs
Up to 2 years
3,590 3,886 3,761 
Long-term debt refinancing costs
Up to 37 years
1,500 1,718 1,799 
Other
Up to 13 years
8,345 4,985 4,095 
295,865 309,302 297,218 
Total regulatory assets$488,659 $451,046 $476,797 
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Index
Estimated
Recovery or Refund
Period as of
June 30, 2026
*June 30, 2026June 30, 2025December 31, 2025
(In thousands)
Regulatory liabilities:
Current:
Environmental compliance programs
Up to 1 year
$100,186 $72,520 $89,306 
Natural gas costs refundable through rate adjustments
Up to 1 year
34,598 44,377 47,130 
Electric fuel and purchased power deferral
Up to 1 year
10,465 934 — 
Margin sharing
Up to 1 year
4,065 3,410 3,946 
Taxes refundable to customers
Up to 1 year
2,313 2,197 2,301 
Provision for rate refund
Up to 1 year
1,353 4,254 1,780 
Conservation programs
Up to 1 year
851 1,996 733 
Other
Up to 1 year
3,120 4,566 3,388 
156,951 134,254 148,584 
Noncurrent:
Plant removal and decommissioning costsOver plant lives230,673 225,142 224,313 
Taxes refundable to customersOver plant lives171,179 180,212 176,665 
Cost recovery mechanisms
Up to 16 years
46,098 35,794 41,323 
Accumulated deferred investment tax creditOver plant lives22,831 19,814 22,663 
Pension and postretirement benefits**4,776 4,862 4,776 
Other
Up to 12 years
2,848 2,344 2,589 
478,405 468,168 472,329 
Total regulatory liabilities$635,356 $602,422 $620,913 
Net regulatory position$(146,697)$(151,376)$(144,116)
*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.
As of June 30, 2026 and 2025, and December 31, 2025, approximately $178.9 million, $177.2 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.
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The following tables summarize the Company's significant regulatory proceedings and cases by jurisdiction:
SegmentStateFiling DateAnnual Revenue Increase (%) *
Annual Revenue Increase
(In millions) *
ROE*StatusKey Drivers and Additional Information
General Rate Cases Pending
ElectricMontanaSeptember 30, 202515.0 %$10.0 9.65 %
•Settlement filed
•Interim rate increase of $10.4M or 16.2% effective April 1, 2026
•Investments, including Badger Wind Farm
•Corresponding depreciation on those investments
•Increased operation and maintenance expense
Natural Gas DistributionOregonNovember 25, 202511.8 %$12.2 9.50 %
•Settlement filed
•Requested rates to be effective October 31, 2026
•Rate base growth
•Growth in operations and maintenance expense
•Growth in depreciation expense associated with new investments in rate base
Natural Gas DistributionWashingtonMay 29, 2026
Rate Year 1

4.9%
Rate Year 2

3.4%
Rate Year 1

$25.1
Rate Year 2

$18.1
10.50 %
•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, 202613.5 %$31.0 14.59 %
•Pending
•Rates to be effective December 1, 2026
•Increase in proposed depreciation rates represent 30% of the annual revenue increase
ElectricNorth DakotaJune 30, 202614.5 %$34.5 10.80 %
•Pending
•Requested interim rate increase of $26.3M or 11.0% effective September 1, 2026
•Increase in operations and maintenance expense
•Investments made across the system since the last filing
•Higher depreciation expense related to infrastructure investments
General Rate Cases Finalized
Natural Gas DistributionWashingtonMarch 29, 2024
Rate Year 1

7.9%



Rate Year 2

2.6%
Rate Year 1

$29.8



Rate Year 2

$10.8
9.50 %
Approved February 24, 2025
Final rates effective March 5, 2025
$3.7M revenue reduction effective June 1, 2025**

Final rates effective March 1, 2026
Filed for a $2.1M revenue reduction effective June 1, 2026**
•Multi-year rate case
•Infrastructure investments necessary to provide safe and reliable service
•Higher operating costs due to inflation
•$3.7M revenue reduction was driven by forecasted plant that was not placed in service by December 31, 2024
•$2.1M revenue reduction was driven by forecasted plant that was not placed in service by December 31, 2025
ElectricWyomingJune 30, 202518.6 %$5.8 9.70 %
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
*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.
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SegmentStateFiling Date
Annual Revenue Increase
(In millions)
StatusKey Drivers and Additional Information
Other Filings
Natural Gas DistributionWyomingAugust 15, 2025N/ARequest denied May 19, 2026
System Safety and Integrity Rider
•Would allow Montana-Dakota to recover costs and expenses associated with a pipeline replacement program
ElectricMontanaSeptember 30, 2025N/AWithdrawn as part of rate case settlement agreement
Systems Management Cost Adjustment Mechanism
•Recovery of transmission and wildfire related costs
ElectricSouth DakotaOctober 31, 2025$1.1 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.
The Company recognizes revenue from the sale of emissions allowances allocated under the environmental programs when the allowances are sold at auction. The revenues associated with the sale of these allowances are deferred as a component of the respective jurisdiction’s regulatory liability for environmental compliance.
As environmental allowances are surrendered, the segment reduces the associated environmental compliance assets and liabilities from the Consolidated Balance Sheets. The expenses and revenues associated with the Company’s environmental allowances and obligations are deferred as regulatory assets and liabilities and recognized as a component of purchased natural gas sold as recovered in customer rates. For more information on the Company’s regulatory assets and liabilities, see Note 10.
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.
The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of insurance contracts, to satisfy its obligations under its unfunded, nonqualified defined benefit and defined contribution plans for executive officers and certain key management employees and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $70.4 million, $64.1 million and $67.4 million, at June 30, 2026 and 2025, and December 31, 2025, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gain on these investments was $4.6 million and $4.1 million for the three and six months ended June 30, 2026, respectively. The net unrealized gain on these investments was $3.0 million and $2.6 million for the three and six months ended June 30, 2025, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in Other income on the Consolidated Statements of Income. In the first quarter of 2026 and second quarter of 2025, the Company withdrew $4.0 million and $5.0 million, respectively, of cash in excess of 125 percent of the full funding amount, which had no effect on the cost basis of the investments held.
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The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as Investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in Accumulated other comprehensive loss on the Consolidated Balance Sheets. Details of available-for-sale securities were as follows:
June 30, 2026CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair Value
(In thousands)
Mortgage-backed securities$8,638 $1 $261 $8,378 
U.S. Treasury securities3,767 33 5 3,795 
Total$12,405 $34 $266 $12,173 
June 30, 2025CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair Value
(In thousands)
Mortgage-backed securities$8,403 $24 $260 $8,167 
U.S. Treasury securities3,416 53 2 3,467 
Total$11,819 $77 $262 $11,634 
December 31, 2025CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair Value
(In thousands)
Mortgage-backed securities$8,539 $28 $204 $8,363 
U.S. Treasury securities3,992 33 — 4,025 
Total$12,531 $61 $204 $12,388 
The Company's assets measured at fair value on a recurring basis were as follows:
Fair Value Measurements at June 30, 2026, Using
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)		Balance at June 30, 2026
(In thousands)
Assets:
Money market funds$— $9,191 $— $9,191 
Insurance contracts*— 70,381 — 70,381 
Available-for-sale securities:
Mortgage-backed securities— 8,378 — 8,378 
U.S. Treasury securities— 3,795 — 3,795 
Total assets measured at fair value$— $91,745 $— $91,745 
*The insurance contracts invest approximately 52 percent in fixed-income investments, 20 percent in common stock of large-cap companies, 11 percent in target date investments, 8 percent in common stock of mid-cap companies, 4 percent in common stock of small-cap companies, 3 percent in cash equivalents, 1 percent in international investments, and 1 percent in real estate.
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Fair Value Measurements at June 30, 2025, Using
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)		Balance at June 30, 2025
(In thousands)
Assets:
Money market funds$— $8,965 $— $8,965 
Insurance contracts*— 64,141 — 64,141 
Available-for-sale securities:
Mortgage-backed securities— 8,167 — 8,167 
U.S. Treasury securities— 3,467 — 3,467 
Total assets measured at fair value$— $84,740 $— $84,740 
*The insurance contracts invest approximately 56 percent in fixed-income investments, 18 percent in common stock of large-cap companies, 10 percent in target date investments, 7 percent in common stock of mid-cap companies, 4 percent in common stock of small-cap companies, 4 percent in cash equivalents, and 1 percent in international investments.
Fair Value Measurements at December 31, 2025, Using
Quoted Prices in
Active Markets
for Identical
Assets
 (Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
 (Level 3)		Balance at December 31, 2025
(In thousands)
Assets:
Money market funds$— $9,839 $— $9,839 
Insurance contracts*— 67,409 — 67,409 
Available-for-sale securities:
Mortgage-backed securities— 8,363 — 8,363 
U.S. Treasury securities— 4,025 — 4,025 
Total assets measured at fair value$— $89,636 $— $89,636 
*The insurance contracts invest approximately 57 percent in fixed-income investments, 18 percent in common stock of large-cap companies, 10 percent in target date investments, 7 percent in common stock of mid-cap companies, 4 percent in common stock of small-cap companies, 3 percent in cash equivalents, and 1 percent in international investments.
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.
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The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was categorized as Level 2 in the fair value hierarchy and was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt was as follows:
June 30, 2026June 30, 2025December 31, 2025
(In thousands)
Carrying amount$2,577,157 $2,181,935 $2,676,855 
Fair value$2,338,445 $1,886,060 $2,385,170 
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 June 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:

CompanyDebt-to-Total Capitalization Ratio at June 30, 2026Provisions for Increased Borrowings, up to a maximum of:Facility
Limit		Amount Outstanding at June 30, 2026Amount Outstanding at June 30, 2025Amount Outstanding at December 31, 2025Letters of Credit at June 30, 2026Expiration
Date
(In millions)
Montana-Dakota Utilities Co.51 %$250.0 $200.0 $82.0 $43.3 $132.0 $— 12/11/30
Cascade Natural Gas Corporation49 %$225.0 $175.0 $108.3 $14.0 $96.5 $2.2 12/11/30
Intermountain Gas Company53 %$225.0 $175.0 $77.9 $86.8 $67.3 $— 12/11/30
MDU Resources Group, Inc.47 %$250.0 $200.0 $45.0 $— $32.9 $1.0 12/11/30
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Long-term Debt Outstanding
Long-term debt outstanding was as follows:
Weighted
Average
Interest
Rate at
June 30, 2026
June 30, 2026June 30, 2025December 31, 2025
(In thousands)
Senior Notes due on dates ranging from July 15, 2026 to June 15, 20624.83 %$2,110,000 $1,947,000 $2,010,000 
Credit agreements due on December 11, 20305.27 %231,150 100,800 196,700 
Term Loan Agreements due on dates ranging from January 31, 2027 to March 31, 20394.04 %126,900 61,600 310,900 
Commercial paper supported by revolving credit agreement4.06 %82,000 43,300 132,000 
Medium-Term Notes due on dates ranging from September 15, 2027 to March 16, 20297.32 %35,000 35,000 35,000 
Other notes due on November 30, 20386.00 %321 338 329 
Less unamortized debt issuance costs8,214 6,103 8,074 
Total long-term debt2,577,157 2,181,935 2,676,855 
Less current maturities4,700 136,700 144,700 
Net long-term debt$2,572,457 $2,045,235 $2,532,155 

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 February 2026 and March 2026, Montana-Dakota paid down $100.0 million and $80.0 million of the outstanding balance under the term loan agreement, respectively. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans, and investments.

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 is expected to be issued 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.

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 June 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 June 30, 2026 was 39 percent.
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Note 14 - Business segment data
The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's CODM, the chief executive officer. The Company's operations are located within the United States.
The Company's CODM regularly reviews discrete financial information of each reportable segment and uses net income to assess 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.
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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 June 30, 2026ElectricNatural gas distributionPipelineOtherConsolidated
(In thousands)
Operating revenues:
External operating revenues$115,916 $212,647 $46,740 $— $375,303 
Intersegment operating revenues124 86 10,052 201 10,463 
Purchased natural gas sold:
External purchased natural gas sold— 93,538 — — 93,538 
Intersegment purchased natural gas sold— 9,900 — — 9,900 
Electric fuel and purchased power38,674 — — — 38,674 
Operation and maintenance:
External operation and maintenance31,015 60,741 22,247 13 114,016 
Intersegment operation and maintenance124 86 152 201 563 
Depreciation and amortization20,287 26,639 8,257 — 55,183 
Taxes, other than income5,368 16,806 3,773 — 25,947 
Other income:
External other income1,842 3,865 242 278 6,227 
Intersegment other income— — 76 326 402 
Interest expense:
External interest expense11,094 15,945 3,801 708 31,548 
Intersegment interest expense— — 402 — 402 
Income tax expense (benefit)(3,343)(3,215)4,042 5,867 3,351 
Income (loss) from continuing operations14,663 (3,842)14,436 (5,984)19,273 
Discontinued operations, net of tax— — — 1,967 1,967 
Net income (loss)
$14,663 $(3,842)$14,436 $(4,017)$21,240 
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Three Months Ended June 30, 2025ElectricNatural gas distributionPipelineOtherConsolidated
(In thousands)
Operating revenues:
External operating revenues$97,886 $206,794 $46,507 $(1)$351,186 
Intersegment operating revenues140 92 9,796 180 10,208 
Purchased natural gas sold:
External purchased natural gas sold— 96,057 — — 96,057 
Intersegment purchased natural gas sold— 9,751 — — 9,751 
Electric fuel and purchased power34,891 — — — 34,891 
Operation and maintenance:
External operation and maintenance29,823 60,456 22,352 256 112,887 
Intersegment operation and maintenance140 92 45 180 457 
Depreciation and amortization17,393 26,471 7,989 — 51,853 
Taxes, other than income4,648 16,935 3,583 — 25,166 
Other income:
External other income2,726 5,095 1,616 508 9,945 
Intersegment other income— — 90 1,061 1,151 
Interest expense:
External interest expense7,614 13,745 3,135 951 25,445 
Intersegment interest expense— — 1,151 — 1,151 
Income tax expense (benefit)(4,254)(4,170)4,337 4,742 655 
Income (loss) from continuing operations
10,497 (7,356)15,417 (4,381)14,177 
Discontinued operations, net of tax— — — (397)(397)
Net income (loss)
$10,497 $(7,356)$15,417 $(4,778)$13,780 
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Six Months Ended June 30, 2026ElectricNatural gas distributionPipelineOtherConsolidated
(In thousands)
Operating revenues:
External operating revenues$236,934 $674,994 $69,352 $— $981,280 
Intersegment operating revenues291 175 44,512 400 45,378 
Purchased natural gas sold:
External purchased natural gas sold— 332,929 — — 332,929 
Intersegment purchased natural gas sold— 44,320 — — 44,320 
Electric fuel and purchased power84,741 — — — 84,741 
Operation and maintenance:
External operation and maintenance59,720 125,867 43,016 318 228,921 
Intersegment operation and maintenance291 175 192 400 1,058 
Depreciation and amortization39,914 52,972 16,476 — 109,362 
Taxes, other than income10,888 43,258 7,531 — 61,677 
Other income:
External other income2,293 6,135 (181)585 8,832 
Intersegment other income— — 191 1,131 1,322 
Interest expense:
External interest expense23,005 32,231 6,903 2,094 64,233 
Intersegment interest expense— — 1,322 — 1,322 
Income tax (benefit) expense
(8,255)9,211 8,744 (1,671)8,029 
Income from continuing operations29,214 40,341 29,690 975 100,220 
Discontinued operations, net of tax— — — 1,837 1,837 
Net income$29,214 $40,341 $29,690 $2,812 $102,057 
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Six Months Ended June 30, 2025ElectricNatural gas distributionPipelineOtherConsolidated
(In thousands)
Operating revenues:
External operating revenues$210,147 $746,041 $69,831 $— $1,026,019 
Intersegment operating revenues318 187 43,132 358 43,995 
Purchased natural gas sold:
External purchased natural gas sold— 413,214 — — 413,214 
Intersegment purchased natural gas sold— 43,074 — — 43,074 
Electric fuel and purchased power78,639 — — — 78,639 
Operation and maintenance:
External operation and maintenance58,230 123,939 41,592 173 223,934 
Intersegment operation and maintenance318 187 58 358 921 
Depreciation and amortization34,576 52,593 15,945 — 103,114 
Taxes, other than income9,463 47,563 6,897 — 63,923 
Other income:
External other income3,718 8,396 1,923 905 14,942 
Intersegment other income— — 213 2,047 2,260 
Interest expense:
External interest expense15,501 28,621 6,256 1,889 52,267 
Intersegment interest expense— — 2,260 — 2,260 
Income tax (benefit) expense
(7,985)8,131 9,464 (384)9,226 
Income from continuing operations25,441 37,302 32,627 1,274 96,644 
Discontinued operations, net of tax— — — (899)(899)
Net income$25,441 $37,302 $32,627 $375 $95,745 
A reconciliation of reportable segment operating revenues to consolidated operating revenues is as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In thousands)
Operating revenues reconciliation:
Total reportable segment operating revenues$385,565 $361,215 $1,026,258 $1,069,656 
Other revenue201 179 400 358 
Elimination of intersegment operating revenues(10,463)(10,208)(45,378)(43,995)
Total consolidated operating revenues$375,303 $351,186 $981,280 $1,026,019 
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 EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands)
Components of net periodic benefit cost:
Interest cost$3,128 $3,303 $6,256 $6,606 
Expected return on assets(3,392)(3,645)(6,783)(7,290)
Amortization of net actuarial loss1,432 1,194 2,864 2,387 
Net periodic benefit cost$1,168 $852 $2,337 $1,703 
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Components of net periodic benefit credit for the Company's other postretirement benefit plans were as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2026202520262025
(In thousands)
Components of net periodic benefit credit:
Service cost$94 $99 $188 $198 
Interest cost441 462 882 924 
Expected return on assets(1,270)(1,292)(2,540)(2,584)
Amortization of prior service credit(45)(289)(90)(579)
Amortization of net actuarial gain(23)(80)(46)(160)
Net periodic benefit credit, including amount capitalized(803)(1,100)(1,606)(2,201)
Less amount capitalized17 18 35 36 
Net periodic benefit credit$(820)$(1,118)$(1,641)$(2,237)
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 June 30, 2026 and 2025, respectively, and $1.3 million and $1.4 million for the six months ended June 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 June 30, 2026 and 2025, and December 31, 2025, the Company accrued liabilities, which have not been discounted, of $24.6 million, $25.0 million and $26.1 million, respectively. The Company also recorded corresponding receivables of $69,000, $1.4 million, and $1.6 million, at June 30, 2026 and 2025, and December 31, 2025, respectively. The Company recorded regulatory assets of $22.7 million, $22.3 million and $23.2 million, at June 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 June 30, 2026, the fixed maximum amounts guaranteed under these letters of credit aggregated $3.2 million, all of which have scheduled expiration of the maximum amounts in 2026. There were no amounts outstanding under the previously mentioned letters of credit at June 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 June 30, 2026, approximately $12.4 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 six months ended June 30, 2026 or 2025. At June 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 June 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 $22.6 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 The Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 88-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.
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 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 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 EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions, except per share amounts)
Electric$14.7 $10.4 $29.2 $25.4 
Natural gas distribution(3.9)(7.4)40.3 37.3 
Pipeline14.4 15.4 29.7 32.6 
Other(5.9)(4.3)1.0 1.3 
Income from continuing operations19.3 14.1 100.2 96.6 
Discontinued operations, net of tax2.0 (.4)1.9 (.9)
Net income$21.3 $13.7 $102.1 $95.7 
Earnings per share - basic:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - basic$.10 $.07 $.49 $.47 
Earnings per share - diluted:
Income from continuing operations$.09 $.07 $.48 $.47 
Discontinued operations, net of tax.01 — .01 — 
Earnings per share - diluted$.10 $.07 $.49 $.47 
Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 The Company's consolidated earnings increased $7.6 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. Interim rates in Montana and new rates in Wyoming, along with higher retail sales volumes across all major customer classes, further drove the increase. The increase was partially offset by higher interest expense associated with debt issuances for recent capital investments, including Badger Wind Farm, as well as higher depreciation expense and operation and maintenance expense, primarily related to Badger Wind Farm.
•The natural gas distribution business reported a decreased seasonal loss, primarily driven by new rates in Idaho, Washington, Montana and Wyoming, as well as higher retail sales volumes across all customer classes. These impacts were partially offset by higher interest expense resulting from higher long-term debt balances.
•The earnings decrease at the pipeline business was driven by lower other income and higher depreciation and amortization expense from a growth project placed in service. These impacts were partially offset by continued customer demand for short-term natural gas transportation contracts and interruptible storage services, as well as contributions from previously constructed growth projects, including a contracted volume increase.
•Other experienced an increase in net income primarily due to 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. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate.
Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 The Company's consolidated earnings increased $6.4 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. Interim rates in Montana and new rates in Wyoming further drove the increase. The increase was partially offset by higher interest expense associated with debt issuances for recent capital investments, including Badger Wind Farm, as well as higher depreciation expense and operation and maintenance expense, primarily related to Badger Wind Farm.
•The natural gas distribution business reported an increase in earnings, primarily driven by new rates in Washington, Idaho, Montana and Wyoming. The increase was partially offset by lower retail sales and electric generation transportation volumes due to warmer first quarter weather. Higher interest expense resulting from higher debt balances, lower other income, and higher operation and maintenance expense, primarily attributable to increased payroll-related costs, further offset the increase.
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•The decrease in earnings at the pipeline business was driven by lower other income. The business also incurred higher operation and maintenance expense, primarily attributable to higher payroll-related costs, materials, and consulting and legal costs associated with the business's recently filed rate case. Lower interruptible natural gas storage withdrawals and higher Montana property tax accruals also contributed to the decrease. These impacts were partially offset by continued customer demand for 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 income primarily due to 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. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate.
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 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 EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions)
Operating revenues$116.1 $98.1 $237.3 $210.5 
Operating expenses:
Electric fuel and purchased power38.6 34.9 84.7 78.6 
Operation and maintenance31.2 29.9 60.1 58.5 
Depreciation and amortization20.3 17.4 39.9 34.6 
Taxes, other than income5.4 4.7 10.9 9.5 
Total operating expenses95.5 86.9 195.6 181.2 
Operating income20.6 11.2 41.7 29.3 
Other income1.9 2.7 2.3 3.7 
Interest expense11.2 7.6 23.1 15.5 
Income before income taxes11.3 6.3 20.9 17.5 
Income tax benefit(3.4)(4.1)(8.3)(7.9)
Net income$14.7 $10.4 $29.2 $25.4 
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Operating statisticsThree Months EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
Revenues (millions)
Retail sales:
Residential$35.3 $28.3 $74.4 $66.5 
Commercial1
48.8 41.2 95.7 86.4 
Industrial11.0 9.1 20.9 17.9 
Other2.0 1.8 4.0 3.5 
97.1 80.4 195.0 174.3 
Other19.0 17.7 42.3 36.2 
$116.1 $98.1 $237.3 $210.5 
Volumes (million kWh)
Retail sales:
Residential253.4 235.8 585.4 606.5 
Commercial1
732.1 672.7 1,474.0 1,396.6 
Industrial128.7 120.0 249.4 236.7 
Other20.1 20.1 39.3 40.3 
1,134.3 1,048.6 2,348.1 2,280.1 
Average cost of electric fuel and purchased power per kWh$.026 $.024 $.027 $.025 
1Commercial includes the impact from data centers.
Cooling degree days (% warmer (colder) than prior year)1
Montana(8.2)%30.3 %(6.0)%31.9 %
North Dakota2.6 %35.7 %3.6 %35.7 %
South Dakota8.2 %52.3 %12.7 %52.4 %
Wyoming(7.8)%(16.4)%0.5 %(14.3)%
1Cooling degree days are a measure of the energy demand for cooling.
Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Electric earnings increased $4.3 million as a result of:
•Revenue increased $18.0 million.
◦Largely due to:
▪Higher renewable tracker revenues of $7.7 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 $3.7 million recovered in customer rates and offset in expense, as described below.
▪New rates approved in regulatory proceedings of $3.4 million in Montana and Wyoming.
▪Higher retail sales volumes of $1.8 million across all major customer classes.
•Electric fuel and purchased power increased $3.7 million, largely the result of higher demand costs and higher volumes.
•Operation and maintenance increased $1.3 million.
◦Largely the result of:
▪Higher contract services related to Badger Wind Farm of $1.0 million. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station planned outage-related costs.
▪Higher payroll-related costs of $600,000.
◦Partially offset by absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income as described below, and timing of software expenses.
•Depreciation and amortization increased $2.9 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.
•Taxes, other than income increased $700,000, largely as a result of higher property tax, primarily in North Dakota and Montana.
•Other income decreased $800,000, largely the result of lower TSA income, as described above, partially offset by higher returns on the Company's nonqualified benefit plan investments.
•Interest expense increased $3.6 million, primarily due to higher long-term debt balances.
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•Income tax benefit decreased $700,000, largely due to higher income before income taxes, partially offset by higher production tax credits of $500,000 driven by Badger Wind Farm as discussed above.
Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Electric earnings increased $3.8 million as a result of:
•Revenue increased $26.8 million.
◦Largely due to:
▪Higher renewable tracker revenues of $14.4 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 $6.1 million recovered in customer rates and offset in expense, as described below.
▪New rates approved in regulatory proceedings of $3.6 million in Montana and Wyoming.
◦Partially offset by lower retail sales volumes of $800,000, driven primarily by lower residential and commercial volumes, largely due to warmer weather in the first quarter of the year. There was an increase in commercial volumes from data centers as further discussed in the Outlook section.
•Electric fuel and purchased power increased $6.1 million, largely the result of higher demand costs and higher volumes.
•Operation and maintenance increased $1.6 million.
◦Largely the result of:
▪ Higher contract services related to Badger Wind Farm of $2.0 million. 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 $1.4 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 $5.3 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.
•Taxes, other than income increased $1.4 million, largely as a result of higher property tax, primarily in North Dakota and Montana.
•Other income decreased $1.4 million, largely the result of lower TSA income, as described above, and lower AFUDC due to lower average CWIP balances, partially offset by higher returns on the Company's nonqualified benefit plan investments.
•Interest expense increased $7.6 million, primarily due to higher long-term debt balances.
•Income tax benefit increased $400,000, largely due to higher production tax credits of $1.5 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 EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions)
Operating revenues$212.6 $206.9 $675.1 $746.2 
Operating expenses:
Purchased natural gas sold103.4 105.8 377.2 456.3 
Operation and maintenance60.8 60.5 126.0 124.1 
Depreciation and amortization26.6 26.5 53.0 52.6 
Taxes, other than income16.8 17.0 43.3 47.6 
Total operating expenses207.6 209.8 599.5 680.6 
Operating income (loss)5.0 (2.9)75.6 65.6 
Other income3.8 5.1 6.1 8.4 
Interest expense15.9 13.8 32.2 28.6 
Income (loss) before income taxes(7.1)(11.6)49.5 45.4 
Income tax (benefit) expense(3.2)(4.2)9.2 8.1 
Net income (loss)$(3.9)$(7.4)$40.3 $37.3 
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Operating statisticsThree Months EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
Revenues (millions)
Retail sales:
Residential$111.1 $106.1 $370.6 $397.7 
Commercial63.5 63.4 213.7 253.0 
Industrial8.7 9.4 22.1 25.1 
183.3 178.9 606.4 675.8 
Transportation and other29.3 28.0 68.7 70.4 
$212.6 $206.9 $675.1 $746.2 
Volumes (MMdk)
Retail sales:
Residential9.1 8.5 35.6 40.3 
Commercial7.4 7.0 26.0 28.9 
Industrial1.1 1.0 2.6 2.7 
17.6 16.5 64.2 71.9 
Transportation sales:
Commercial.3 .3 .9 1.1 
Industrial32.4 38.1 71.3 86.5 
32.7 38.4 72.2 87.6 
Total throughput50.3 54.9 136.4 159.5 
Average cost of natural gas per dk$5.88 $6.42 $5.88 $6.35 
Heating degree days (% colder (warmer) than prior year)1
Idaho7.9 %(21.7)%(15.3)%(0.9)%
Minnesota14.0 %21.4 %(6.2)%16.8 %
Montana8.5 %(2.6)%(23.9)%6.4 %
North Dakota2
15.7 %14.1 %(8.6)%12.6 %
Oregon2
3.0 %(12.4)%(7.6)%(1.4)%
South Dakota2
11.5 %5.2 %(21.4)%9.7 %
Washington2
(10.5)%(22.7)%(12.6)%(3.3)%
Wyoming4.0 %12.9 %(22.9)%10.5 %
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 June 30, 2026, Compared to Three Months Ended June 30, 2025 Natural gas distribution reported a decreased seasonal loss of $3.5 million as a result of:
•Revenue increased $5.7 million.
◦Largely due to:
▪New rates approved in regulatory proceedings of $7.7 million, primarily in Idaho, Washington, Montana and Wyoming.
▪Higher Montana property tax tracker of $700,000 that was offset in expense, as described below.
▪A 6.7 percent or $500,000 increase in retail sales volumes to all customer classes, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.
◦Partially offset by:
▪Lower purchased natural gas sold of $2.4 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
▪Transportation volumes decreased 14.8 percent or $500,000 primarily the result of lower electric generation volumes.
▪Lower revenue-based taxes of $400,000, recovered in rates and offset in expense, as described below.
•Purchased natural gas sold decreased $2.4 million, largely due to lower commodity costs of $9.6 million, partially offset by higher volumes of natural gas purchased of $7.0 million, and net environmental compliance costs of $200,000.
•Operation and maintenance increased $300,000.
◦Largely the result of higher payroll-related costs of $2.2 million.
◦Partially offset by absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income, as described below, and timing of software expenses.
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•Depreciation and amortization increased $100,000, of which $1.1 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 $1.0 million.
•Taxes, other than income decreased $200,000, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, including Montana, which is recovered in rates, as discussed above.
•Other income decreased $1.3 million, largely the result of lower TSA income as described above, partially offset by higher returns on the Company's nonqualified benefit plan investments.
•Interest expense increased $2.1 million, primarily due to higher long-term debt balances.
•Income tax benefit decreased $1.0 million, primarily the result of lower seasonal loss before income taxes.
Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Natural gas distribution earnings increased $3.0 million as a result of:
•Revenue decreased $71.1 million.
◦Largely due to:
▪Lower purchased natural gas sold of $79.1 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
▪Lower revenue-based taxes of $4.9 million, recovered in rates and offset in expense, as described below.
▪A 10.7 percent or $3.8 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 17.6 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 $17.1 million, primarily in Washington, Idaho, Montana and Wyoming.
▪Higher conservation revenues of $1.3 million that were offset in expense, as described below.
•Purchased natural gas sold decreased $79.1 million, largely due to lower volumes of natural gas purchased of $48.6 million, commodity costs of $20.8 million and net environmental compliance costs of $9.7 million.
•Operation and maintenance increased $1.9 million.
◦Largely due to:
▪Higher payroll-related costs of $3.4 million.
▪Higher contract services of $1.3 million, including higher rate case expenses.
▪Higher insurance expenses of $1.0 million.
▪Higher conservation-related costs, recovered in rates, as discussed above.
◦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 $400,000, of which $2.5 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 $2.1 million.
•Taxes, other than income decreased $4.3 million, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, largely in Montana and Washington.
•Other income decreased $2.3 million.
◦Primarily due to:
▪Lower TSA revenue of $2.5 million, as described above.
▪Lower net interest income on regulatory deferral balances.
◦Partially offset by:
▪Higher returns on the Company's nonqualified benefit plans of $800,000.
•Interest expense increased $3.6 million, primarily due to higher long-term debt balances.
•Income tax expense increased $1.1 million, primarily the result of 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. The EPA has not issued a federal implementation plan in place of the state plan. In January 2025, the Coyote Station co-owners filed a petition challenging the plan disapproval for review with the Eighth Circuit. This action is currently being held in abeyance. In February 2025, the co-owners filed a petition for reconsideration with the EPA, which was granted in April 2025. In October 2025, the EPA released an advanced notice of proposed rulemaking seeking input on restructuring the program with the intent to streamline regulatory requirements for states' visibility improvement obligations. The Electric Generation GHG Rule and Mercury and Air Toxics Standards Rule, as discussed below, also have the potential to impact the operation of Coyote Station. The Company is one of four owners of Coyote Station and cannot make a unilateral decision on the plant's future; therefore, the Company could be negatively impacted by decisions of the other owners. The joint owners continue to collaborate in analyzing data and weighing decisions that impact the plant and its employees as well as each company's customers and communities served.
In December 2025, the Company completed the acquisition of a 49 percent ownership interest in Badger Wind Farm and placed the asset in service. The completed transaction secures 122.5 MW of the project's total 250 MW generation capacity for the Company and follows the NDPSC's Advance Determination of Prudence and Certificate of Public Convenience and Necessity approvals, confirming the project is a prudent, cost-effective investment for customers.
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. Approximately 60 MW of the incremental data center load is currently online, with the remaining capacity available and awaiting Applied Digital's request to increase service. Load at the second HPC building in Ellendale is expected to begin ramping in the third quarter of 2026. The third HPC building at Ellendale is scheduled to begin ramping in January 2027.
In June 2026, the Company announced the signing of a new electric service agreement to serve its 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 is still pending along with an updated conditional use permit for the data center siting with McPherson County.
The Company's approach to serving data center customers, is grounded in protecting existing customers and ensuring that growth creates values for the communities the Company serves. Data center customers are responsible for paying the costs associated with connecting to and being served by the electric system, including infrastructure and energy-related expenses. Through careful planning, regulatory oversight and cost-allocation mechanisms, the Company works to ensure that existing customers are not subsidizing the costs of serving these new customers. At the same time, the additional revenue generated from serving data center customers can help support the electric system and contribute to reducing certain fixed costs by allocating them across a broader customer base. The Company believes this current approach creates benefits for all customers.
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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. A final rule is expected in 2026. The Company continues to monitor this rulemaking.
◦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 in litigation.
◦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. Comments were due in June 2026.
•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 first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow.
•In Washington, the Climate Commitment Act was adopted by the Washington Legislature in 2021 and became effective in 2023. The Climate Commitment Act establishes a cap-and-invest program designed to reduce GHG emissions over time, while using auctioned allowances to fund state energy and environmental policy goals. The Company intends to meet its compliance obligations through a combination of energy efficiency measures, no-cost allowances, purchased allowances, and carbon offsets. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, the purchase of allowances could impact the Company's operating cash flow.
•The Washington SBCC in 2023 adopted residential and commercial building code amendments that will significantly limit the use of natural gas for space and water heating in new and retrofitted commercial and residential buildings. In May 2024, the Company filed a joint complaint seeking declaratory and injunctive relief under federal law against the Washington SBCC's adoption of the amended Washington State Energy Code. This complaint was dismissed by the federal district court. Petitioners have appealed this decision to the 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.
Initiative Measure No. 2066, which was approved by voters, does not allow the Washington State Energy Code to "in any way prohibit, penalize, or discourage the use of gas for any form of heating, or for uses related to any appliance or equipment, in any building." In May 2025, the King County Superior Court filed an order ruling Initiative Measure No. 2066 unconstitutional. Following the ruling, the Building Industry Association of Washington filed a notice of appeal with the King County Superior Court. The King County Superior Court’s order invalidating Initiative Measure No. 2066 is now pending review by the Washington State Supreme Court. The Court heard oral arguments in the case in January 2026.
•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.
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Pipeline
Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in 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 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 EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions)
Operating revenues$56.7 $56.3 $113.8 $113.0 
Operating expenses:
Operation and maintenance22.4 22.4 43.2 41.7 
Depreciation and amortization8.3 7.9 16.5 15.9 
Taxes, other than income3.7 3.6 7.5 6.9 
Total operating expenses34.4 33.9 67.2 64.5 
Operating income22.3 22.4 46.6 48.5 
Other income.3 1.7 — 2.1 
Interest expense4.2 4.3 8.2 8.5 
Income before income taxes18.4 19.8 38.4 42.1 
Income tax expense4.0 4.4 8.7 9.5 
Net income$14.4 $15.4 $29.7 $32.6 
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Operating statisticsThree Months EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
Transportation volumes (MMdk)150.4 151.4 293.6 294.9 
Customer natural gas storage balance (MMdk):
Beginning of period27.3 22.1 37.6 44.1 
Net injection (withdrawal)14.2 12.5 3.9 (9.5)
End of period41.5 34.6 41.5 34.6 
Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Pipeline earnings decreased $1.0 million as a result of:
•Revenues increased $400,000 as a result of:
◦Increased demand revenue, largely due to:
▪Increased usage of short-term natural gas transportation contracts of $1.0 million.
▪Growth projects placed in service of $400,000.
◦Higher storage-related revenue of $400,000.
◦Partially offset by:
▪Lower interruptible transportation volumes of $700,000.
▪Lower non-regulated project revenue of $600,000, partially offset in operation and maintenance expense, as described below.
•Operation and maintenance was comparable to the same period last year.
◦Primarily from:
▪Higher payroll-related costs of $700,000.
▪Higher consulting and legal costs associated with the Company's recent rate case filing.
▪Partially offset by lower non-regulated project costs of $600,000, associated with decreased non-regulated project revenue, as previously discussed.
◦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 $400,000 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 $1.4 million.
◦Largely due to:
▪Project development costs incurred in 2026 that were not eligible for capitalization of $800,000.
▪Lower TSA income of $800,000, as described above.
▪Partially offset by higher investment returns on the Company's non-qualified benefit plans of $300,000.
•Interest expense decreased $100,000, primarily from lower debt fees and higher AFUDC, largely offset by higher debt balances.
•Income tax expense decreased $400,000, largely due to lower income before income taxes.
Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Pipeline earnings decreased $2.9 million as a result of:
•Revenues increased $800,000 as a result of:
◦Increased demand revenue, largely due to:
▪Increased usage of short-term natural gas transportation contracts of $1.4 million.
▪Growth projects placed in service of $800,000.
◦Higher non-regulated project revenue of $700,000, partially offset in operation and maintenance expense, as described below.
◦Partially offset by:
▪Lower interruptible transportation volumes of $1.2 million.
▪Lower storage-related revenue of $800,000.
•Operation and maintenance increased $1.5 million.
◦Primarily from:
▪Higher payroll-related costs of $1.0 million.
▪Higher materials costs of $800,000.
▪Higher consulting and legal costs associated with the Company's recent rate case filing.
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▪Higher non-regulated project costs of $400,000, associated with increased non-regulated project revenue, as previously discussed.
◦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 $600,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.
•Taxes, other than income increased $600,000, largely due to higher property tax accruals in Montana.
•Other income decreased $2.1 million:
◦Largely due to:
▪Lower TSA income of $900,000, as described above.
▪Project development costs incurred in 2026 that were not eligible for capitalization of $900,000.
•Interest expense decreased $300,000, primarily from higher AFUDC.
•Income tax expense decreased $800,000, 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.
•Potential Bakken East Pipeline project, which could consist of 350 miles of pipeline construction from western North Dakota to the eastern part of the state, plus additional pipeline laterals. A Binding Open Season concluded in March 2026, with customer requests of approximately 1.4 billion cubic feet per day of natural gas transportation capacity obtained through this process. With recently signed Precedent Agreements, the Company has now executed agreements with all customers that submitted binding open season interest totaling nearly 1.2 billion cubic feet per day of firm natural gas transportation capacity, with a negotiated option in place that may increase contracted volumes to nearly all of the original interest from the Binding Open Season. The Company continues to design the project for 1.4 billion cubic feet per day of transportation capacity. Overall project design is being finalized based on confirmed customer volumes and delivery locations before a final investment decision is made, which is expected ahead of a FERC Section 7(c) application. This application is now anticipated to be filed in the fourth quarter of 2026. Included in the open season results is a firm capacity commitment from the State of North Dakota of up to $50 million annually for 10 years, reinforcing the strategic importance of the project to the region's energy infrastructure and economic development opportunities. As development progresses, the Company continues to evaluate all financing options to support the projected $2.7 billion to $3.2 billion project. This investment would be incremental to the Company's capital investment plan. The Company continues to advance engineering, environmental review and pre-filing activities for the proposed
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Bakken East Project and incur preliminary development costs associated with those activities, which are included in other noncurrent assets on the Company's Consolidated Balance Sheets. The Company has certain contractual and commercial arrangements in place that are intended to mitigate the Company's financial exposure associated with these investments and will continue to evaluate these amounts and their classification in conjunction with project developments as they occur. Phase One of the proposed project is targeted to be complete in late 2029, with Phase Two targeted to be complete in late 2030.
•Potential Minot Industrial Pipeline Project, which could consist of an approximately 90-mile pipeline from Tioga, North Dakota to Minot, North Dakota and ancillary facilities. The Company has signed an agreement to support the early stage development of the project which has been extended through late 2026. The project would provide incremental natural gas transportation capacity for anticipated industrial demand.
Other
Three Months EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions)
Operating revenues$.2 $.1 $.4 $.3 
Operating expenses:
Operation and maintenance.2 .4 .7 .5 
Total operating expenses.2 .4 .7 .5 
Operating loss— (.3)(.3)(.2)
Other income.6 1.6 1.7 3.0 
Interest expense.6 .9 2.0 1.9 
Income (loss) before income taxes— .4 (.6).9 
Income tax (benefit) expense5.9 4.7 (1.6)(.4)
Income (loss) from continuing operations(5.9)(4.3)1.0 1.3 
Discontinued operations, net of tax2.0 (.4)1.9 (.9)
Net income (loss)$(3.9)$(4.7)$2.9 $.4 
Three and Six Months Ended June 30, 2026, Compared to Three and Six Months Ended June 30, 2025
For both the quarter and year-to-date periods, Other reported increased earnings compared to the same periods in 2025. The increases were primarily due to 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. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate.
Other includes the activities of the captive insurer which insures various types of risks of the Company's subsidiaries. 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 EndedSix Months Ended
June 30,June 30,
2026 2025 2026 2025 
(In millions)
Intersegment transactions:
Operating revenues$10.4 $10.2 $45.4 $44.0 
Purchased natural gas sold$9.9 $9.8 $44.3 $43.1 
Operation and maintenance$.5 $.4 $1.1 $.9 
Other income$.4 $1.2 $1.3 $2.3 
Interest expense$.4 $1.2 $1.3 $2.3 
For more information on intersegment eliminations, see Note 14.
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Liquidity and Capital Commitments
At June 30, 2026, the Company had cash, cash equivalents and restricted cash of $46.3 million and available borrowing capacity of $433.7 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year and its other operating and capital requirements from various sources, including internally generated funds; credit facilities and commercial paper of the Company and its subsidiaries, as described in Capital resources; and issuance of debt securities and equity securities using the Company's FSA and ATM program, as needed.
Cash flows
Six Months Ended
June 30,
2026 2025 
(In millions)
Net cash provided by (used in):
Operating activities$265.3 $334.9 
Investing activities(196.1)(174.4)
Financing activities(51.1)(168.6)
Increase (decrease) in cash, cash equivalents and restricted cash18.1 (8.1)
Cash, cash equivalents and restricted cash -- beginning of year28.2 66.9 
Cash, cash equivalents and restricted cash -- end of period
$46.3 $58.8 
Operating activities 
Six Months Ended
June 30,
2026 2025 Variance
(In millions)
Components of net cash provided by operating activities:
Net income$102.1 $95.7 $6.4 
Loss from discontinued operations, net of tax
1.9 (0.9)2.8 
Income from continuing operations100.2 96.6 3.6 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization109.4 103.1 6.3 
Deferred income taxes11.6 (19.0)30.6 
Other adjustments4.5 4.0 .5 
Changes in current assets and liabilities, net of acquisitions:
Receivables103.8 129.5 (25.7)
Inventories19.3 25.0 (5.7)
Other current assets(23.0)86.7 (109.7)
Accounts payable(36.4)(47.6)11.2 
Other current liabilities(7.6)(28.4)20.8 
Pension & postretirement benefit plan contributions(1.0)(2.5)1.5 
Other noncurrent changes(16.8)(11.8)(5.0)
Net cash provided by continuing operations264.0 335.6 (71.6)
Net cash provided by (used in) discontinued operations1.3 (.7)2.0 
Net cash provided by operating activities$265.3 $334.9 $(69.6)
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 $71.6 million lower, primarily attributable to:
◦Other current assets $(109.7) million: due to lower collections of purchased gas costs of $43.0 million, carbon compliance costs of $31.7 million, decoupling balances of $8.2 million, all at the natural gas distribution business; as well as lower fuel cost collections at the electric business of $7.1 million.
◦Receivables $(25.7) million: due to lower collection of accounts receivable due to warmer than normal weather in December 2025.
◦Other noncurrent changes $(5.0) million: due to increased preliminary project costs incurred in 2026 versus 2025.
◦Partially offset by:
▪Deferred income taxes $30.6 million: which resulted from higher plant related deferrals of $14.4 million, purchased gas cost adjustments of $9.8 million, and environmental compliance deductions of $2.2 million.
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▪Other current liabilities $20.8 million: due to higher environmental compliance obligations due to customers of $26.2 million, a large load customer deposit of $12.0 million, and higher electric fuel balances owed to customers of $9.5 million; partially offset by lower income taxes paid of $30.6 million.
Investing activities
Six Months Ended
June 30,
2026 2025 Variance
(In millions)
Components of net cash used in investing activities:
Capital expenditures$(193.5)$(174.0)$(19.5)
Cost of removal, net of salvage value(3.9)(2.5)(1.4)
Purchase of investment securities(2.7)(2.9).2 
Proceeds from investment securities
4.0 5.0 (1.0)
Net cash used in investing activities$(196.1)$(174.4)$(21.7)
•Net cash used in investing activities was $21.7 million higher, primarily attributable to:
◦Capital expenditures $(19.5) million: due to higher natural gas distribution expenditures of $27.9 million, partially offset by lower electric wind project expenditures of $12.2 million.
Financing activities
Six Months Ended
June 30,
2026 2025 Variance
(In millions)
Components of net cash used in financing activities:
Issuance of long-term debt$134.5 $— $134.5 
Repayment of long-term debt(234.0)(111.0)(123.0)
Debt issuance costs(.6)— (.6)
Issuance of common stock, net
110.8 — 110.8 
Dividends paid(57.3)(53.1)(4.2)
Tax withholding on stock-based compensation(4.5)(4.5)— 
Net cash used in financing activities$(51.1)$(168.6)$117.5 
•Net cash used in financing activities was $117.5 million lower, primarily attributable to:
◦Issuance of long-term debt $134.5 million: of which $100.0 million of senior notes were issued under a NPA and $34.5 million was issued under the revolving credit agreement facilities.
◦Issuance of common stock $110.8 million: of which $81.2 million was partial settlement under the Company's FSA and $29.6 million was net issuances under the Company's ATM program.
◦Partially offset by:
▪Repayment of long-term debt $(123.0) million: due to increased repayments primarily at Montana-Dakota.
▪Dividends paid $(4.2) million: higher dividends paid 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 six months of 2026 and 2025 were $193.8 million and $179.4 million, respectively. Capital expenditures at the Company's business segments are estimated to be approximately $529.2 million for 2026, which is a slight reduction to what was previously reported in the 2025 Annual Report due to the timing of JETx capital expenditures. 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. Investment in the potential Bakken East Pipeline project would be incremental to the outlined capital program. 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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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 June 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 June 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 June 30, 2026, the Company had capacity to issue up to an aggregate gross sales price of $370.0 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 June 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 June 30, 2026, the Company estimates that the counterparties, in aggregate, would have been entitled to a net settlement of $16.8 million or 792,557 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 estimated interest payments, asset retirement obligations and uncertain tax positions for 2026 from those reported in the 2025 Annual Report. 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.
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.
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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 now expects to contribute 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 June 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 June 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.
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)
April 1 through April 30, 2026— $— — — 
May 1 through May 31, 2026— — — — 
June 1 through June 30, 20261,445 21.27 — — 
Total1,445 $21.27 — — 
(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 June 30, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
Item 6. Exhibits
See the index to exhibits immediately preceding the signature page to this report.
50
Index
Exhibits Index
Incorporated by Reference
Exhibit NumberExhibit DescriptionFiled
Herewith		FormPeriod
Ended		ExhibitFiling
Date		File Number
3(a)8-K3.25/8/191-03480
3(b)8-K3.12/14/251-03480
+10(a)8-K10.15/13/261-03480
31(a)X
31(b)X
*32
X
101.INSXBRL 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.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
+Management contract, compensatory plan, or arrangement.
*Furnished Herewith
51
Index
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:August 6, 2026BY:/s/ Jason L. Vollmer
Jason L. Vollmer
Chief Financial Officer
BY:/s/ Stephanie A. Sievert
Stephanie A. Sievert
Chief Accounting and Regulatory Affairs Officer


52

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