MDU RESOURCES GROUP INC
For the period ended Mar 31, 2026. Filed May 7, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 7, 2026
MDU$18.63+0.5%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-10.
0000067716-25-000090
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-07.
0000067716-26-000050
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 259 previous paragraphs and 171 current paragraphs.
61 unchanged; 70 reworded; 35 added; 118 removed; 10 previous and 5 current paragraphs rearranged.
Tables are not compared: 14 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (35)
Current report
•The electric business earnings decrease was largely the result of higher interest expense associated with debt issuances for recent capital investments including Badger Wind Farm. Lower retail sales volumes due to warmer weather and higher depreciation expense, primarily Badger Wind Farm, further drove the decrease. Higher retail revenues, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm, largely offset the decrease.
Current report
•Revenue increased $8.8 million.
Current report
•Operation and maintenance increased $300,000.
Current report
◦Largely the result of $1.4 million higher contract services related to Badger Wind Farm of $900,000 and timing of tree trimming of $400,000. 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.
Current report
◦Partially offset by timing of software expenses.
Current report
•Depreciation and amortization increased $2.4 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.
Current report
•Other income decreased $600,000, largely the result of lower AFUDC due to lower average CWIP balances.
Current report
•Interest expense increased $4.0 million, primarily due to higher long-term debt balances.
Current report
•Revenue decreased $76.8 million.
Current report
▪A 15.9 percent or $4.3 million decrease in retail sales volumes to all customer classes due to warmer weather, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.
Current report
▪Transportation volumes decreased 19.7 percent or $1.7 million primarily the result of lower electric generation volumes largely due to warmer weather.
Current report
◦Partially offset by:
Current report
▪Higher payroll-related costs of $1.2 million.
Current report
▪Higher contract services, including higher subcontractor costs and rate case expenses.
Current report
▪Higher insurance claims of $800,000.
Current report
◦Partially offset by:
Current report
▪Timing of software-related expenses.
Current report
•Interest expense increased $1.5 million, primarily due to higher long-term debt balances.
Current report
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.
Current report
◦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.
Current report
◦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.
Current report
◦The Company determined the Effluent Limitations Guidelines Rule and related amendments do not have a material impact on the Company.
Current report
◦In April 2026, the EPA proposed amendments to federal regulations for coal combustion residuals at legacy coal ash sites. The Company is evaluating the proposal. Comments are due in June 2026.
Current report
•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.
Current report
•Revenues increased $400,000 as a result of:
Current report
▪Growth projects placed in service of $400,000.
Current report
▪Higher payroll-related costs of $400,000.
Current report
•Other income decreased $700,000, largely due to lower investment returns on the Company's non-qualified benefit plans of $300,000.
Current report
The cash used in investing activities decreased compared to 2025, primarily due to excess cash above the 125% funding limit withdrawn from the Company's unfunded, nonqualified defined benefit plans.
Current report
The cash used in financing activities decreased compared to 2025, primarily due to 2026 long term debt issuances and net proceeds from the issuance of common stock, partially offset by lower long term debt repayments, including line of credit repayments.
Current report
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.
Current report
Equity offerings
Current report
On December 5, 2025, the Company completed a follow-on public offering of 10,152,284 of shares of the Company's common stock at a public offering price of $19.70 per share. In addition, on December 23, 2025, the underwriters exercised their option to purchase 1,522,842 additional shares of the Company's common stock. Pursuant to the FSAs entered into in connection with the offering, the Company has 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.
Current report
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 March 31, 2026, the Company could have settled all of its outstanding FSAs with physical delivery of 7,375,126 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 March 31, 2026, the Company estimates that the counterparties, in aggregate, would have been entitled to a net settlement of $13.2 million or 635,500 shares, respectively.
Current report
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.
Removed paragraphs (118)
Previous report
Strategic Initiatives On October 31, 2024, the Company completed the separation of Everus, its former construction services business, resulting in Everus becoming an independent, publicly-traded company. The Company's board of directors approved the distribution of all the outstanding shares of Everus common stock to the Company's stockholders. Stockholders of the Company received one share of Everus common stock for every four shares of the Company's common stock held as of the close of business on October 21, 2024, the record date for the distribution. The separation of Everus was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes, except for cash received in lieu of fractional shares.
Previous report
The Company incurred costs in connection with its strategic initiatives in 2024 and 2025, as noted in the Business Segment Financial and Operating Data section. The majority of the separation costs have already been incurred due to the separation of Everus in October 2024, as previously discussed.
Previous report
One Big Beautiful Bill Act On July 4, 2025, the reconciliation bill was enacted into law, extending key provisions of the 2017 Tax Cuts and Jobs Act while scaling back clean energy tax incentives of the IRA. Changes in tax laws may affect recorded deferred tax assets and deferred tax liabilities or the Company's effective tax rates in the future. The Company has evaluated new legislation, and it does not expect a material impact to the consolidated financial statements or ongoing tax rate as a result of this legislation.
Previous report
On October 31, 2024, the Company completed the separation of Everus, its former construction services business, into a new independent publicly-traded company. As a result of the separation, the historical results of operations for Everus are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the Company, which did not meet the criteria for discontinued operations and are reflected in Other. Also included in discontinued operations are certain strategic initiative costs associated with the separation of Everus.
Previous report
•The electric business earnings decrease was largely the result of higher operation and maintenance expense, primarily due to increased payroll-related costs and higher contract services related to electric generation station outage-related costs. Higher depreciation expense, primarily associated with capital projects placed in service, further drove the decrease. The decrease in net income was partially offset by higher retail sales revenue.
Previous report
•Other experienced lower operation and maintenance expense, primarily a result of corporate overhead costs classified as continuing operations allocated to Everus in 2024, which are not included in Other in 2025, and lower insurance claims experience at the captive insurer. Other was negatively impacted by higher income tax adjustments related to the Company's annualized estimated tax rate.
Previous report
•As previously discussed, the Company was adversely impacted by the absence of income from discontinued operations in 2025.
Previous report
Nine Months Ended September 30, 2025, Compared to Nine Months Ended September 30, 2024 The Company's consolidated earnings decreased $111.8 million. The decrease in earnings is primarily due to the absence of income from discontinued operations in 2025.
Previous report
•The electric business earnings decrease was largely the result of higher operation and maintenance expense, primarily due to higher payroll-related costs, higher contract services related to electric generation station outage-related costs, increased software expenses, which includes certain costs associated with TSA services provided, and higher insurance expense. The decrease in net income was partially offset by higher retail sales volumes, partly from a data center near Ellendale, North Dakota.
Previous report
•The natural gas distribution earnings improvement was largely the result of higher rate relief in Washington, Montana, South Dakota and Wyoming and increased volumes due to colder weather in certain jurisdictions. These increases were partially offset by higher operation and maintenance expense, primarily due to increased payroll-related costs, higher software expenses, which includes certain costs associated with TSA services provided, and higher insurance expense. Lower interest income also negatively impacted earnings.
Previous report
•The earnings increase at the pipeline business was driven by growth projects placed in service throughout 2024 and customer demand for short-term natural gas transportation contracts. Higher storage-related revenue further drove the increase. The increase was partially offset by higher operation and maintenance expense, primarily attributable to payroll-related costs. The absence of $1.5 million, net of tax proceeds received in 2024 from a customer settlement further offset the increase. The business also incurred higher depreciation expense due to growth projects placed in service, as previously discussed, and higher property tax accruals in Montana.
Previous report
•Other experienced lower operation and maintenance expense, primarily a result of corporate overhead costs classified as continuing operations allocated to Everus in 2024, which are not included in Other in 2025, and lower insurance claims experience at the captive insurer.
Previous report
•As previously discussed, the Company was adversely impacted by the absence of income from discontinued operations in 2025.
Previous report
The Company's CODM, the chief executive officer of MDU Resources Group, Inc., regularly reviews discrete financial information of each reportable segment and uses net income to assess performance of each reportable segment. The CODM uses this information to assess performance and make decisions about resources to be allocated to each reportable segment, including capital and personnel. The information provided to the CODM is prepared at the reportable segment level in quarterly financial packages and on a more summarized basis monthly. Budget and forecast information is also provided to the CODM at the reportable segment level.
Previous report
In second half of 2023, electric fuel and purchased power prices increased across Montana-Dakota's integrated system, and remained elevated through January 2024. This was caused by transmission congestion in northwest North Dakota due to delays in additional SPP transmission line build-out, as well as additional load growth in the Bakken region. To assist in the recovery of the higher electric fuel and purchased power costs, Montana-Dakota filed waiver requests with the NDPSC and SDPUC, deferring the increased costs to the annual fuel clause adjustment. In Montana, the waiver request is filed monthly and was unopposed by the MTPSC. Effective April 1, 2024, as approved by the NDPSC, Montana-Dakota started recovery in North Dakota of these increased costs over a period of two years rather than one year. In South Dakota and Montana, Montana-Dakota recovered these costs over a one-year period effective July 1, 2024. In July 2025, the NDPSC approved Montana-Dakota's request to defer external legal expenses related to this congestion litigation and record those deferred expenses into a regulatory asset. Montana-Dakota and MISO each filed a petition for review of the FERC decision with the Eighth Circuit with a decision expected in the first half of 2026.
Previous report
•Revenue increased $9.3 million, largely due to higher fuel and purchased power costs of $8.7 million recovered in customer rates and offset in expense, as described below.
Previous report
•Operation and maintenance increased $2.7 million.
Previous report
◦Largely the result of:
Previous report
▪Higher payroll-related costs of $2.0 million.
Previous report
▪Higher contract services related to electric generation station outage-related costs of $600,000.
Previous report
•Depreciation and amortization increased $500,000, largely due to increased property, plant, and equipment balances as a result of transmission projects placed in service to improve reliability and update aging infrastructure.
Previous report
•Other income increased $600,000, including higher TSA income, as described above.
Previous report
•Interest expense was comparable to the same period in the prior year.
Previous report
Nine Months Ended September 30, 2025, Compared to Nine Months Ended September 30, 2024 Electric earnings decreased $10.8 million as a result of:
Previous report
•Revenue increased $12.8 million.
Previous report
▪Higher net transmission revenue of $1.9 million, including data center revenue.
Previous report
•Electric fuel and purchased power increased $10.8 million, largely the result of higher retail sales volumes, partially offset by lower commodity prices.
Previous report
•Operation and maintenance increased $14.5 million.
Previous report
◦Largely the result of:
Previous report
▪Higher payroll-related costs of $5.5 million.
Previous report
▪Higher contract services related to electric generation station outage-related costs of $3.7 million.
Previous report
▪Increased software expense of $3.0 million.
Previous report
▪Higher insurance expense.
Previous report
•Depreciation and amortization increased $2.3 million, largely due to increased property, plant, and equipment balances as a result of transmission projects placed in service to improve reliability and update aging infrastructure.
Previous report
•Other income increased $200,000, including higher TSA income, as described above, partially offset by lower interest income from regulatory deferral balances.
Previous report
•Interest expense increased $700,000, largely the result of lower AFUDC, partially offset by lower expense associated with lower average debt balances.
Previous report
Three Months Ended September 30, 2025, Compared to Three Months Ended September 30, 2024 Natural gas distribution reported an increased seasonal loss of $700,000 as a result of:
Previous report
•Revenue increased $10.7 million.
Previous report
▪Higher revenue-based taxes of $700,000, recovered in rates and offset in expense, as described below.
Previous report
•Purchased natural gas sold increased $5.4 million, largely due to higher volumes of natural gas purchased of $8.4 million. This increase was partially offset by lower commodity costs of $1.5 million and net environmental compliance costs of $1.5 million.
Showing the first 40 of 118 passages. Open the source sections for the rest.
Reworded paragraphs (70)
Previous wording
Dividends Based on the Company becoming a pure-play regulated energy delivery business, the Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 87-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.
Current wording
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 87-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.
Previous wording
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. The Company has observed supply chain improvements in lead times for certain commodities. The Company has experienced impacts related to the changes in tariffs and continues to navigate the current environment and monitor the future for impacts that could occur. For more information 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 II, Item 1A. Risk Factors in this Form 10-Q and Part I, Item 1A. Risk Factors in the 2024 Annual Report.
Current wording
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. The Company has observed supply chain improvements in lead times for certain commodities. The Company has experienced impacts related to the changes in tariffs and continues to navigate the current environment and monitor the future for impacts that could occur. For more information 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.
Previous wording
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, trends, objectives, goals, dividend payout ratio targets, 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.
Current wording
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.
Previous wording
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 II, Item 1A. Risk Factors in this quarterly report, Part I, Item 1A. Risk Factors in the 2024 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.
Current wording
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.
Previous wording
Three Months Ended September 30, 2025, Compared to Three Months Ended September 30, 2024 The Company's consolidated earnings decreased $46.2 million. The decrease in earnings is primarily due to the absence of income from discontinued operations in 2025. Other drivers of the earnings decrease include:
Current wording
Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 The Company's consolidated earnings decreased $1.2 million. Drivers of the earnings decrease include:
Previous wording
•The natural gas distribution business reported an increased seasonal loss, largely the result of higher operation and maintenance expense, primarily due to higher payroll-related costs and decreased interest income associated with lower purchased gas costs. Higher depreciation expense, primarily associated with capital projects placed in service, further drove the loss. The seasonal loss was partially offset by higher retail sales revenue due to rate relief in Washington, Montana, and Wyoming, as well as lower interest expense.
Current wording
•The natural gas distribution business reported a decrease in earnings, largely the result of lower retail sales volumes due to warmer weather. Lower electric generation transportation volumes driven by warmer weather, higher operation and maintenance expense, primarily payroll-related expense and contract services, and higher interest expense further drove the decrease. The decrease was largely offset by higher retail sales revenue due to rate relief in Washington, Idaho, Montana, and Wyoming.
Previous wording
•The earnings increase at the pipeline business was driven by higher transportation revenue due to growth projects placed in service in late 2024 and customer demand for short-term natural gas transportation contracts. The increase was offset in part by higher operation and maintenance expense, primarily attributable to payroll-related costs. The business also incurred higher property tax accruals in Montana and higher depreciation expense due to growth projects placed in service.
Current wording
•The earnings decrease at the pipeline business was driven by lower interruptible natural gas storage withdrawals. Higher operation and maintenance expense primarily attributable to higher materials and payroll-related costs also contributed, as well as higher Montana property tax accruals. The decrease was partially offset by continued strong customer demand for short-term natural gas transportation contracts, as well as impacts from a growth project placed in service in 2025 and a contracted volume increase associated with a previously constructed growth project.
Previous wording
For the quarter and year to date, Other reported decreased net income compared to the same periods in 2024. The decreases were primarily due to the absence of income from discontinued operations in 2025 and income tax adjustments related to the Company's annualized estimated tax rate. Partially offsetting the decreases were lower operation and maintenance expenses, primarily a result of corporate overhead costs classified as continuing operations allocated to Everus in 2024, which are not included in Other in 2025, and lower insurance claims experience at the captive insurer.
Current wording
•Other experienced an increase in net income primarily due to income tax adjustments related to the Company's annualized estimated tax rate. Partially offsetting the increase was higher operation and maintenance expense.
Previous wording
For information pertinent to various commitments and contingencies, see the Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Note 15 of the Notes to Consolidated Financial Statements.
Current wording
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.
Previous wording
To date, many states have enacted and others are considering, mandatory clean 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. Recently, MISO and NERC announced concerns with the 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 primarily due to growth in the data center industry. Montana-Dakota filed its 2024 IRP with the NDPSC in July 2024. With MISO's filed changes in resources adequacy at FERC and the adoption of direct loss of load accreditation for generation resources around riskiest hours on the system versus peak load hours, Montana-Dakota is seeing the need to add additional capacity resources to its system in 2028 versus 2034 as identified in its previous IRP. The Company signed a power purchase and ownership purchase agreement with Badger Wind, LLC for 150 MW of output capacity from the 250 MW Badger Wind Project which will reduce the Company's capacity and energy purchase requirements as identified in the 2024 IRP. Montana-Dakota 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.
Current wording
To date, many states have enacted and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns. MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to growth in the data center industry. 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.
Previous wording
Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather, as well as impacts associated with commercial and industrial slow-downs, including economic recessions, and energy efficiencies. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among residential and commercial customers. Average consumption among both electric and natural gas customers has tended to decline as more efficient appliances and furnaces are installed, and as the Company has implemented conservation programs. Natural gas weather normalization and decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins.
Current wording
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.
Previous wording
The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and long lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures have moderated but costs for goods and services remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Part II, Item 1A. Risk Factors in this quarterly report and Part I, Item 1A. Risk Factors in the 2024 Annual Report.
Current wording
The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures have moderated but costs for goods and services remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.
Previous wording
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 JETx line was filed with the NDPSC in August 2025. JETx is expected to be placed in service at the end of 2028.
Current wording
The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to higher costs and long lead times for equipment, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project. The route permit for the JETx line was filed with the NDPSC in August 2025. JETx is expected to be placed in service in 2029.
Previous wording
Three Months Ended September 30, 2025, Compared to Three Months Ended September 30, 2024 Electric earnings decreased $2.8 million as a result of:
Current wording
Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 Electric earnings decreased $500,000 as a result of:
Previous wording
◦Partially offset by lower renewable tracker revenues, partly associated with higher production tax credits offset in income tax benefit, as described below.
Current wording
▪Higher renewable tracker revenues of $6.7 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.
Previous wording
▪Higher fuel and purchased power costs of $10.8 million recovered in customer rates and offset in expense, as described below.
Current wording
▪Higher fuel and purchased power costs of $2.4 million recovered in customer rates and offset in expense, as described below.
Previous wording
▪Higher retail sales volumes of $1.4 million, driven primarily by higher residential volumes, largely due to colder weather in the first quarter of the year, and higher commercial volumes from the data center as further discussed in the Outlook section.
Current wording
◦Partially offset by lower retail sales volumes of $2.6 million, driven primarily by lower residential and commercial volumes, largely due to warmer weather. There was an increase in commercial volumes from data centers as further discussed in the Outlook section.
Previous wording
•Electric fuel and purchased power increased $8.7 million, largely the result of higher commodity prices, partially offset by lower retail sales volumes.
Current wording
•Electric fuel and purchased power increased $2.4 million, largely the result of higher demand costs, primarily driven by data centers.
Previous wording
•Taxes, other than income increased $1.1 million, largely as a result of higher property tax, primarily in Montana.
Current wording
•Taxes, other than income increased $700,000, largely as a result of higher property tax, primarily in North Dakota and Montana.
Previous wording
•Income tax benefit increased $5.5 million, largely due to lower income before income taxes, and higher production tax credits of $1.6 million driven by higher wind production.
Current wording
•Income tax benefit increased $1.1 million, largely due to higher production tax credits of $1.0 million driven by Badger Wind Farm as discussed above, and lower income before income taxes.
Previous wording
Nine Months Ended September 30, 2025, Compared to Nine Months Ended September 30, 2024 Natural gas distribution earnings increased $1.5 million as a result of:
Current wording
Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 Natural gas distribution earnings decreased $500,000 as a result of:
Previous wording
▪Higher purchased natural gas sold of $5.4 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
Current wording
▪Lower purchased natural gas sold of $76.7 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
Previous wording
▪Higher revenue-based taxes of $4.7 million, recovered in rates and offset in expense, as described below.
Current wording
▪Lower revenue-based taxes of $4.5 million, recovered in rates and offset in expense, as described below.
Previous wording
▪Rate relief of $3.7 million, primarily in Washington and Montana.
Current wording
▪Rate relief of $9.4 million, primarily in Washington, Idaho, Montana and Wyoming.
Previous wording
▪Higher conservation revenues of $2.6 million, offset in expense, as described below.
Current wording
▪Higher conservation revenues of $800,000 that were offset in expense, as described below.
Previous wording
▪Higher basic service charges of $800,000 due to customer growth.
Current wording
▪Higher basic service charges of $300,000 due to customer growth.
Previous wording
•Purchased natural gas sold increased $69.5 million, largely due to net environmental compliance costs of $46.2 million, higher volumes of natural gas purchased of $19.5 million and higher commodity costs of $3.8 million.
Current wording
•Purchased natural gas sold decreased $76.7 million, largely due to lower volumes of natural gas purchased of $55.6 million, commodity costs of $11.2 million and net environmental compliance costs of $9.9 million.
Previous wording
•Depreciation and amortization increased $1.6 million, of which $2.0 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented from rates cases in North Dakota, Montana and Wyoming of $500,000.
Current wording
•Depreciation and amortization increased $300,000, of which $1.3 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 $1.1 million.
Previous wording
•Taxes, other than income increased $5.8 million, due to higher revenue-based taxes, as described above, and higher property taxes, largely in Montana and Washington.
Current wording
•Taxes, other than income decreased $4.1 million, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, largely in Montana and Washington.
Previous wording
▪Lower interest on regulatory deferral balances.
Current wording
•Other income decreased $1.0 million, due to lower interest on regulatory deferral balances, primarily lower purchased gas cost deferral balances.
Previous wording
•Income tax expense increased $800,000, primarily the result of changes in permanent tax adjustments and higher income before income taxes.
Current wording
•Income tax expense increased $100,000, primarily the result of higher permanent tax adjustments, partially offset by lower income before income taxes.
Previous wording
Outlook In 2024, the utility business experienced rate base growth of 6.8 percent and expects these segments will grow rate base by approximately 7 percent to 8 percent annually over the next five years on a compound basis. Operations are spread across eight states where the Company expects customer growth to be higher than the national average. In 2024, these segments experienced retail customer growth of approximately 1.4 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.
Current wording
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.
Previous wording
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 benefit from lower natural gas prices through the Company's utilization of storage and fixed price contracts.
Current wording
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.
Previous wording
The EPA's GHG and mercury emissions standards finalized in May 2024 would have required additional pollution controls for Coyote Station to operate beyond 2031 and 2027, respectively. In April 2025, the EPA granted a two year extension for Coyote Station to add pollution controls to comply with the mercury emissions standard. In June 2025, the EPA proposed rules to repeal both the mercury emissions standard and the electric generation GHG emissions standard. If the rules go into effect, it could require owners of Coyote station to incur significant new costs. These costs could, dependent on determination by state regulatory commissions on approval to recover such costs from customers, negatively impact the Company's results of operations, financial position and cash flows. In December 2024, the EPA issued a final decision on the NDDEQ's Regional Haze state implementation plan, maintaining the proposed disapproval of the state's conclusion that no additional controls are warranted during this implementation period. The EPA did not issue a federal implementation plan in place of the state plan and would have two years from the state plan disapproval to either propose a federal plan or approve a new state plan. Coyote Station co-owners filed a petition for review with the Eighth Circuit in January 2025, challenging EPA's NDDEQ state plan disapproval, and in February 2025, filed a petition for reconsideration with the EPA, which was granted in April 2025. In June 2025, the Eighth Circuit granted a request by the EPA to continue to hold the petition of review proceeding in abeyance so that the EPA could review the previous administration's findings and actions. In March 2025, the EPA announced the agency is restructuring the regulations for implementing the Regional Haze Program. Further, in October 2025, the EPA released an advanced notice of proposed rulemaking seeking input on restructuring the program with the intent to streamline regulatory requirements for states' visibility improvement obligations. The Company is one of four owners of Coyote Station and cannot make a unilateral decision on the plant's future; therefore, the Company could be negatively impacted by decisions of the other owners. The joint owners continue to collaborate in analyzing data and weighing decisions that impact the plant and its employees as well as each company's customers and communities served.
Current wording
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.
Previous wording
In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, which is the equivalent of about 28 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact other customers' power supply. An electric service agreement to serve an additional 350 MW data center load with Applied Digital in the Company's service territory was approved by the NDPSC. 100 MW of the additional data center load is expected to be fully online in the second quarter of 2026.
Current wording
In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, which is the equivalent of about 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact other customers' power supply. An electric service agreement to serve an additional 350 MW data center load with Applied Digital in the Company's service territory was approved by the NDPSC. Approximately 50 MW of the incremental data center load is currently online with an additional 50 MW expected to be fully online by the end of the second quarter of 2026.
Previous wording
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 final approvals of the data center siting with McPherson County.
Current wording
In August 2024, the Company filed a request with the SDPUC seeking approval on an electric service agreement to provide up to 50 MW of electricity to a data center near Leola, South Dakota. Construction of the data center and approval of the electric service agreement which had been pending development of new local siting requirements for data center loads by McPherson County in South Dakota, were effective August 5, 2025. Approval of the electric service agreement with the SDPUC is still pending filing an updated conditional use permit for the data center siting with McPherson County.
Previous wording
Legislation and rulemaking The Company continues to monitor legislation and rulemaking related to clean energy standards that may impact its segments. Below are some of the specific actions the Company is monitoring.
Current wording
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.
Previous wording
•In May 2024, the EPA published four final rules, three of which will impose stricter standards on GHG emissions from existing coal-fired and new natural gas-fired generation units, require a further reduction of mercury emissions from coal-fired generation units, and impose additional regulations around the storage and management of coal ash. In March 2025, the EPA announced reconsideration of the Electric Generation and Greenhouse Gas Rule, Mercury and Air Toxics Standards Rule, and Effluent Limitations Guidelines Rule. Comments on certain of these proposed rules were due in August 2025. If the rules were to remain as originally proposed and if the costs to comply with these rules are not fully recoverable from customers, they could have a material adverse effect on the Company's results of operations and cash flows.
Current wording
•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.
Previous wording
•In July 2024, the ODEQ released the Climate Protection Program Rule, which was adopted by the Oregon Environmental Quality Commission in November 2024. The Company intends to meet its obligations through surrendering 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 low carbon fuel projects such as RNG and purchasing associated environmental attributes. 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.
Current wording
•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. 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.
Previous wording
•In Washington, the Climate Commitment Act was effective in 2023. 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.
Current wording
•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.
Showing the first 40 of 70 pairs. Open the source sections for the rest.
Rearranged current paragraphs (5)
Current report — wording carried from elsewhere
•Operation and maintenance increased $1.6 million.
Current report — wording carried from elsewhere
◦Operation and maintenance increased $1.5 million.
Current report — wording carried from elsewhere
•Taxes, other than income increased $500,000, largely due to higher property tax accruals in Montana.
Current report — wording carried from elsewhere
Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025
Current report — wording carried from elsewhere
Other reported increased net income compared to the same period in 2025. The increase was primarily due to income tax adjustments related to the Company's annualized estimated tax rate. Partially offsetting the increase was higher operation and maintenance expense.
Rearranged previous paragraphs (10)
Previous report — wording carried elsewhere
•Taxes, other than income increased $1.0 million, largely as a result of higher property tax, primarily in Montana.
Previous report — wording carried elsewhere
▪Higher purchased natural gas sold of $69.5 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.
Previous report — wording carried elsewhere
▪Higher basic service charges of $1.6 million due to customer growth.
Previous report — wording carried elsewhere
•In November 2025, the Minot Expansion Project was placed in service and increased system capacity by 7 MMcf of natural gas per day.
Previous report — wording carried elsewhere
◦Higher non-regulated project revenue of $600,000.
Previous report — wording carried elsewhere
◦Increased demand revenue, largely due to:
Previous report — wording carried elsewhere
▪Increased usage of short-term natural gas transportation contracts of $3.7 million.
Previous report — wording carried elsewhere
◦Higher non-regulated project revenue of $500,000.
Previous report — wording carried elsewhere
▪Higher non-regulated project costs of $800,000, associated with increased non-regulated project revenue as previously discussed.
Previous report — wording carried elsewhere
•Depreciation and amortization increased $2.2 million driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.