What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2026-02-20 compared with 2025-02-20 · 288 added, 505 removed, 495 unchanged (62% of the section changed)

Management's Discussion and Analysis of Financial Condition and Results of Operations

The Company provides essential services, delivering reliable energy that powers lives.

Through its infrastructure investments and operations the Company drives economic growth, supports communities, and energizes businesses that keep America moving.

The Company generates, transmits and distributes electricity and provides natural gas distribution, transportation and storage services.

Through a strategy focusing on its "CORE," the Company strives to deliver superior value and achieve industry-leading performance as a pure-play regulated energy delivery company, while pursuing organic growth opportunities.

The Company's "CORE" strategy prioritizes customers and communities, operational excellence, returns focused initiatives and an employee driven culture.

Strategic Initiatives On May 31, 2023, the Company completed the separation of Knife River, its construction materials and contracting business, resulting in Knife River becoming an independent, publicly-traded company.

3 unchanged sentences

The separation of Knife River was a tax-free spinoff transaction to the Company's stockholders for U.S.

federal income tax purposes.

federal income tax purposes, except for cash received in lieu of fractional shares.

On October 31, 2024, the Company completed the separation of Everus, its construction services business, resulting in Everus becoming an independent, publicly-traded company.

3 unchanged sentences

federal income tax purposes, except for cash received in lieu of fractional shares.

The Company incurred costs in connection with the strategic initiatives in 2022, 2023 and 2024, as noted in the Business Segment Financial and Operating Data section, and expects the majority of the separation costs have already been incurred.

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.

Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, higher interest rates, 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 incurred costs in connection with the strategic initiatives in 2023, 2024 and 2025, as noted in the Business Segment Financial and Operating Data section.

One Big Beautiful Bill Act On July 4, 2025, the reconciliation bill was enacted into law, extending key provisions of the 2017 Tax Cuts and Jobs Act while scaling back clean energy tax incentives of the IRA.

Changes in tax laws may affect recorded deferred tax assets and deferred tax liabilities or the Company's effective tax rates in the future.

The Company has evaluated new legislation, and it does not expect a material impact to the consolidated financial statements or ongoing tax rate as a result of this legislation.

Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, interest rates, changes in tariffs, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business.

The Company has observed supply chain improvements in lead times for certain commodities.

Although the Company has started to see some reduction to interest rates, they remain elevated and have resulted in and may continue to result in increased borrowing costs on new debt, impacts to the Company's asset valuations and negatively impacting the purchasing power of its customers.

The Company has experienced impacts related to the changes in tariffs and continues to navigate the current environment and monitor the future for impacts that could occur.

For more information on possible impacts to the Company's businesses, see the Outlook for each segment below and Item 1A - Risk Factors.

22 unchanged sentences

Also included in discontinued operations are certain strategic initiative costs associated with the separations of Knife River and Everus.

Other includes activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023 compared to the full year in 2022.

2024 compared to 2023 The Company's consolidated earnings decreased $133.6 million primarily due to the absence of the Company's 2023 gain of $186.6 million related to the tax-free exchange of its retained shares in Knife River, partially offset by increased earnings at the pipeline and electric businesses.

• The electric business experienced higher retail sales revenue due to rate relief in North Dakota, South Dakota and Montana.

Lower volumes from the majority of customers, primarily due to cooler weather in the second quarter, and higher operation and maintenance expense, primarily contract services costs, partially offset the increases.

• Decreased earnings at the natural gas distribution business was largely the result of higher operation and maintenance expense, primarily higher contract services costs, higher payroll-related costs, and higher software expenses.

Also decreasing net income was higher depreciation and amortization expense, primarily due to increased asset additions.

These decreases were partially offset by higher retail sales revenue, primarily due to rate relief in North Dakota and South Dakota.

• The pipeline's earnings increase was driven by higher transportation volumes, primarily from growth projects placed in service in November 2023 and throughout 2024 and increased contracted volume commitments beginning February 2023.

Higher storage-related revenue and a full year of new transportation and storage service rates in 2024 further drove the increase.

The business also benefited from proceeds received from a customer settlement that was recorded in other income and a decrease in the Company's effective state income tax rate.

The increase was offset in part by higher operation and maintenance expense primarily attributable to payroll-related costs and higher materials, contract services and pipeline safety fees.

The business incurred higher depreciation and amortization expense due to growth projects placed in service as discussed earlier, which was partially offset by fully depreciated assets.

The business also incurred higher interest expense largely as a result of higher debt balances and higher property taxes.

• Other was impacted by the absence of the Company's 2023 gain of $186.6 million related to the tax-free exchange of its retained shares in Knife River.

Partially offsetting the decrease in net income was lower operation and maintenance expense, largely a result of corporate overhead costs classified as continuing operations allocated to the construction materials business in 2023, which are not included in Other in 2024, and lower strategic initiative costs.

Other also benefited from lower interest expense due to lower borrowings associated with funding strategic initiatives.

Other includes activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023.

Results of Operations The Company's discussion and analysis for the year ended December 31, 2025 compared to 2024 is included herein.

For discussion and analysis for the year ended December 31, 2024 compared to 2023 refer to Part II, Item 7.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025.

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

• Earnings at the electric business were impacted by higher operation and maintenance expense, primarily increased payroll-related costs, contract services related to Coyote Station planned outage-related costs, software expense, which include certain costs associated with services provided under the Transition Services Agreement with Everus that are recovered in other income, and insurance expense.

Partially offsetting the increased operation and maintenance expense were higher retail sales revenue and retail sales volumes, partially driven by a data center near Ellendale, North Dakota.

• Increased earnings at the natural gas distribution business was largely the result of higher retail sales revenue, driven largely by rate relief in Washington, Montana, South Dakota and Wyoming.

The increase was partially offset by higher operation and maintenance expense, primarily higher insurance expense, payroll-related costs, and software expense, which include certain costs associated with services provided under the Transition Services Agreement with Everus that are recovered in other income.

MDU Resources Group, Inc.

2023 compared to 2022 The Company's consolidated earnings increased $47.2 million.

The Company experienced increased earnings at each of its continuing businesses.

• The electric business experienced higher retail sales due to rate relief in North Dakota and Montana, an electric service agreement to provide power to a data center near Ellendale, North Dakota, and higher transmission interconnect upgrades.

Electric earnings were partially offset by lower residential volumes, primarily due to cooler weather in the third quarter of the year.

• Natural gas distribution experienced higher retail sales revenue due to rate relief in Idaho and Washington, higher basic service charges, and recovery of short-term debt interest expense in Idaho related to increased gas costs.

These increases were largely offset by higher operation and maintenance expense, primarily higher payroll-related costs.

The natural gas distribution business also experienced a 6.6 percent decrease in retail sales volumes to all customer classes, largely due to warmer weather, which was partially offset by weather normalization and decoupling mechanisms.

• The pipeline's earnings increase was driven by higher transportation volumes, primarily from increased contracted volume commitments from the North Bakken Expansion project and a full year of benefit from this project;

as well as organic growth projects placed in service in November 2023 and August 2022.

In addition, revenues increased from new transportation and storage rates effective August 1, 2023 and higher storage-related activity.

The pipeline also benefited from higher allowance for funds used during construction on organic growth projects, lower property taxes and higher non-regulated project margin.

The increase was offset in part by higher operation and maintenance expense primarily attributable to payroll-related costs and contract services.

The pipeline business also incurred higher interest expense as a result of higher interest rates and higher debt balances.

• Other experienced a realized gain of $186.6 million related to the tax-free exchange of its retained interest in Knife River and higher interest income.

Partially offsetting these items were higher interest expense, primarily related to debt issued in connection with the Knife River separation.

Other also benefited from improved claims experience at the captive insurer in 2023 compared to 2022.

• The Company's earnings from continuing operations were further impacted by $18.6 million in higher returns on the Company's nonqualified benefit plan investments, as discussed in Note 9, partially offset by higher costs incurred in connection with other strategic initiatives of $6.1 million, after tax.

• The pipeline's slight earnings increase was driven by growth projects placed in service throughout 2024 and in late 2025 and customer demand for short-term firm natural gas transportation contracts.

Higher use of the company's interruptible natural gas transportation services further drove the increase.

The increase was partially offset by higher operation and maintenance expense primarily attributable to payroll-related costs.

The increase was further offset by the absence of $1.5 million, net of tax proceeds received in 2024 from a customer settlement as well as the absence of a benefit from an adjustment related to the Company's effective state income tax rate change.

The business also incurred higher depreciation expense due to growth projects placed in service, as previously discussed, and higher property taxes in Montana.

• Other was impacted by the absence of the income from discontinued operations in 2025.

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

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

Business Segment Financial and Operating Data

Following are 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.

The following are key financial and operating data for each of the Company's business segments.

Highlights of key growth strategies, projections and certain assumptions for the Company and its subsidiaries, and other matters concerning the Company's business segments are included below.

Many of these highlighted points are "forward-looking statements." For more information, see Part I - Forward-Looking Statements.

2 unchanged sentences

Changes in such assumptions and factors could cause actual future results to differ materially from the Company's projections.

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.

For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements.

For a summary of the Company's business segments, see Item 8 - Note 14.

40 MDU Resources Group, Inc.

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 Items 1 and 2 - Business Properties.

Both segments strive to be top performing utility companies with a commitment to customers and communities, operational excellence, returns focused initiatives and an employee driven culture.

The segments provide safe, reliable, competitively priced and environmentally responsible energy service to customers while focusing on growth and expansion opportunities within and beyond its existing territories.

The Company is 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, and through selected acquisitions of companies and properties with similar operating and growth objectives at prices that will provide stable cash flows and an opportunity to earn a competitive return on investment.

Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Item 1 - Business.

Both segments strive to be top performing utilities and provide safe, reliable, competitively priced and environmentally responsible energy services to customers.

The segments are focused on cultivating organic growth while managing operating costs and monitoring opportunities for these segments to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation, transmission and distribution, and natural gas systems.

The continued efforts to create operational improvements and efficiencies across both segments promotes the Company's business integration strategy.

4 unchanged sentences

and economic conditions in the segments' service areas.

MDU Resources Group, Inc.

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 ensuring the delivery of safe, reliable, affordable and environmentally responsible energy.

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.

1 unchanged sentence

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 Items 1 and 2 - Business Properties and Item 8 - Note 20.

For more information on the Company's tracking mechanisms and recent rate cases, see Item 1 - Business and Item 8 - Note 6.

These segments are also subject to extensive regulation related to certain operational and environmental compliance, cybersecurity, permit terms and system integrity.

2 unchanged sentences

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 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, including electric vehicle adoption, as a means to address economy-wide carbon emission concerns, data center growth and changing customer conservation patterns.

Recently, 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.

Montana-Dakota filed its 2024 IRP with the NDPSC on July 12, 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 will continue to monitor the progress of these changes and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures.

To date, many states have enacted, and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply.

Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns.

MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to growth in the data center industry.

Montana-Dakota filed its 2024 IRP with the NDPSC in July 2024.

With MISO's filed changes in resources adequacy at FERC and the adoption of direct loss of load accreditation for generation resources around riskiest hours on the system versus peak load hours, Montana-Dakota identified the need to add additional capacity resources to its system by 2028 versus 2034 as identified in its previous IRP.

The Company previously executed a PPA for 150 MW of output from Badger Wind Farm, which included the option to purchase a 49 percent ownership interest.

With the closing now complete, the PPA has been reduced to 27.5 MW.

The ownership stake in Badger Wind Farm reduced the Company's capacity and energy purchase requirements as identified in the 2024 IRP.

The Company will continue to monitor the progress of these changes, including the impacts associated with the implementation of MISO's direct loss of load accreditation in 2028, and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures.

Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather, as well as impacts associated with commercial and industrial slow-downs, including economic recessions, and energy efficiencies.

1 unchanged sentence

Average consumption among both electric and natural gas customers has tended to decline as more efficient appliances and furnaces are installed, and as the Company has implemented conservation programs.

Natural gas weather normalization and decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins, as further discussed in Items 1 and 2 - Business Properties.

In December 2022 and January 2023, natural gas prices significantly increased across the Pacific Northwest from multiple price-pressuring events including wide-spread below-normal temperatures and higher natural gas consumption;

reduced natural gas flows due to pipeline constraints, including maintenance in West Texas;

and historically low regional natural gas storage levels.

Natural gas prices stabilized by March 2023.

The higher natural gas prices in December 2022 and January 2023 impacted both Intermountain and Cascade, both of which borrowed short-term debt of $125.0 million and $150.0 million, respectively, in January 2023 to finance the increased natural gas costs.

To assist in the recovery of higher natural gas costs, Intermountain filed an out-of-cycle purchased gas adjustment with the IPUC that was effective February 1, 2023, and collected interest costs associated with short-term borrowing.

Effective November 1, 2023, as approved by the WUTC, Cascade started recovery in Washington of these increased gas costs over a period of two years rather than the normal one year period.

In January 2024, Cascade and Intermountain made the final repayment on short-term debt of $50.0 million and $45.0 million, respectively.

For a discussion of the Company's most recent cases by jurisdiction, see Item 8 - Note 20.

MDU Resources Group, Inc.

In late summer and fall of 2023, electric fuel and purchased power prices increased across Montana-Dakota's integrated system.

In the second half of 2023, electric fuel and purchased power prices increased across Montana-Dakota's integrated system and remained elevated through January 2024.

This was caused by transmission congestion in northwest North Dakota due to delays in additional SPP transmission line build-out, as well as additional load growth in the Bakken region.

Electric fuel and purchased power prices remained elevated through January 2024.

To assist in the recovery of the higher electric fuel and purchased power costs, Montana-Dakota filed waiver requests with the NDPSC and SDPUC, which were approved deferring the increased costs to the annual fuel clause adjustment.

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.

Montana-Dakota filed a complaint with FERC related to this issue on January 23, 2024.

MISO also filed its own complaint with FERC against SPP on March 8, 2024.

On September 10, 2024, FERC issued an order denying both Montana-Dakota and MISO's complaint regarding the issue.

On October 10, 2024, Montana-Dakota and MISO filed with FERC for rehearing on FERC's decision to deny these complaints.

Both rehearing requests were denied by operation of law on November 11, 2024.

On January 2, 2025, Montana-Dakota filed a petition for review of the FERC decision with the United States Court of Appeals for the Eighth Circuit.

MISO filed a petition for review of the FERC decision on January 8, 2025.

On December 26, 2024, Montana-Dakota filed a request with the NDPSC for authorization to defer external legal expenses related to this congestion litigation and record those deferred expenses into a regulatory asset.

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, which will lessen the impact to customers and allow more time for Montana-Dakota's FERC complaint to mature and have greater certainty of the outcome.

In South Dakota and Montana, Montana-Dakota started recovery of these costs over a one-year period effective July 1, 2024.

Effective April 1, 2024, as approved by the NDPSC, Montana-Dakota started recovery in North Dakota of these increased costs over a period of two years rather than one year.

In South Dakota and Montana, Montana-Dakota recovered these costs over a one-year period effective July 1, 2024.

In July 2025, the NDPSC approved Montana-Dakota's request to defer external legal expenses related to this congestion litigation and record those deferred expenses into a regulatory asset.

Montana-Dakota and MISO each filed a petition for review of the FERC decision with the Eighth Circuit with a decision expected in the first half of 2026.

The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects.

1 unchanged sentence

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 and inflationary pressures to continue.

The Company expects these delays to continue.

Inflationary pressures have moderated but costs for goods and services remain high.

The Company also continues to monitor the impact tariffs will have on its costs.

Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work.

For additional discussion regarding risks and uncertainties, see Item 1A - Risk Factors.

The ability to grow through acquisitions is subject to significant competition and acquisition premiums.

In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel.

The construction of new electric generating facilities, transmission lines and other service facilities is subject to increasing costs and lead times, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices.

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.

On October 6, 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project.

In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project.

Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project.

The route permit for the JETx line was filed with the NDPSC in August 2025.

JETx is expected to be placed in service at the end of 2028.

42 MDU Resources Group, Inc.

11 unchanged sentences

Operating income 79.6 94.2 92.8 (15.5) % 1.5 %

Other income 8.2 5.8 .5 41 % NM

Other income 7.4 8.2 5.8 (9.8) % 41.4 %

Interest expense 31.7 30.0 28.0 5.7 % 7.1 %

27 unchanged sentences

1 Cooling degree days are a measure of the energy demand for cooling.

2024 compared to 2023 Electric earnings increased $3.2 million as a result of:

• Revenue increased $13.3 million.

◦ Largely attributable to:

▪ Rate relief of $7.1 million in North Dakota, South Dakota and Montana.

▪ Higher fuel and purchased power costs of $6.4 million recovered in customer rates and offset in expense, as described below.

▪ Higher miscellaneous revenue of $2.4 million, including higher transmission interconnect upgrades.

◦ Partially offset by lower retail sales volumes of $2.6 million, driven primarily by lower residential volumes due to 37.0 percent cooler weather in the second quarter of 2024.

There was a 1.2 percent increase in volumes, which includes an increase in commercial volumes from the data center as further discussed in the Outlook section.

MDU Resources Group, Inc.

• Electric fuel and purchased power increased $6.4 million, largely the result of higher commodity prices.

• Operation and maintenance increased $2.3 million, largely the result of increased contract services and higher payroll-related costs.

• Depreciation and amortization increased $2.3 million.

◦ Largely due to:

▪ Increased depreciation of $2.2 million associated with higher property, plant and equipment balances, as a result of transmission projects placed in service to improve reliability and update aging infrastructure.

▪ Higher depreciation rates, which are recovered in operating revenues.

• Taxes, other than income increased $900,000, largely as a result of higher payroll tax and higher property tax, primarily in Montana.

• Other income increased $2.4 million, primarily from:

◦ Higher interest income of $2.7 million, largely related to a data center project of $1.6 million.

◦ Higher short term investment balances.

◦ Amounts related to higher deferred fuel and purchased power balances.

• Interest expense increased $2.0 million, largely the result of higher long-term interest expense due to incremental debt issuances.

• Income tax benefit increased $1.4 million, primarily due to higher production tax credits due to higher wind production.

2023 compared to 2022 Electric earnings increased $14.5 million as a result of:

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

• Revenue increased $23.8 million.

1 unchanged sentence

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

▪ Rate relief of $4.4 million in North Dakota and Montana.

▪ Higher data center revenue of $3.4 million, including net transmission.

▪ Higher transmission interconnect upgrades of $2.9 million.

◦ Partially offset by lower retail sales volumes of $2.4 million, driven primarily by lower residential volumes, largely due to cooler weather in the third quarter of the year.

Although residential volumes were lower, there was a 25.5 percent increase in volumes overall, which was largely driven by the data center as previously discussed and further discussed in the outlook section.

• Electric fuel and purchased power increased $15.4 million, largely due to higher retail sales volumes, partially offset by lower commodity prices.

• Operation and maintenance expense decreased $600,000.

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

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

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

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

• Operation and maintenance increased $16.3 million.

◦ Largely the result of:

◦ Decreased Coyote Station costs of $1.7 million due to the absence of the planned outage in 2022.

◦ Lower materials expense of $500,000, partially due to the closure of Units 1 and 2 at Heskett Station.

◦ Partially offset by increased payroll-related costs, which include higher employee incentive accruals.

• Depreciation and amortization decreased $3.6 million.

◦ Primarily due to decreased amortization of plant retirement and closure costs of $5.3 million resulting from an extension to the recovery period for these costs, which are recovered in operating revenues, as discussed in Note 12.

◦ Partially offset by increased depreciation of $1.2 million associated with higher property, plant and equipment balances, the result of transmission projects placed in service to improve reliability and update aging infrastructure.

• Taxes, other than income were comparable to the same period in the prior year.

• Other income increased $5.3 million.

◦ Largely due to:

▪ Higher returns on the Company's nonqualified benefit plan investments of $4.7 million, as discussed in Note 9.

▪ Higher interest income of $1.3 million, largely related to contributions in aid of construction.

◦ Offset in part by lower AFUDC equity due to higher average debt balance.

• Interest expense decreased $500,000, as a result of higher AFUDC debt, largely due to higher rates, partially offset by higher average interest rates.

• Income tax benefit decreased $4.4 million.

◦ Largely due to:

▪ Higher income taxes of $4.7 million related to higher taxable income.

▪ Decreased excess deferred income tax amortization.

◦ Partially offset by lower permanent tax adjustments.

▪ Higher payroll-related costs of $5.7 million.

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

▪ Increased software expense of $3.2 million.

▪ Higher insurance expense.

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

The transition services are expected to be complete as of March 2026.

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

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

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

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

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

44 MDU Resources Group, Inc.

11 unchanged sentences

Operating income 109.5 92.6 92.2 18.3 % .4 %

Other income 25.5 20.8 3.3 23 % NM

Other income 15.8 25.5 20.8 (38.0) % 22.6 %

Interest expense 59.6 63.2 57.6 (5.7) % 9.7 %

26 unchanged sentences

Idaho (6.1) % (7.3) % (9.0) %

(12.6) % (11.9) % 18.0 %

Minnesota 12.8 % (12.6) % (11.9) %

Montana 4.5 % (4.6) % (2.8) %

5 unchanged sentences

(5.2) % (0.2) % (8.5) %

(9.8) % 1.4 % 1.6 %

Wyoming 7.6 % (9.8) % 1.4 %

1 Heating degree days are a measure of the daily temperature demand for energy for heating.

2 unchanged sentences

2025 compared to 2024 :

Natural gas distribution earnings decreased $1.6 million as a result of:

• Revenue decreased $86.4 million.

◦ Largely from:

▪ Lower purchased natural gas sold and net environmental compliance of $105.8 million offset in expense, as described below.

▪ Absence of 2023 approved rate recovery of short-term debt interest expense of $3.2 million in Idaho related to increased gas costs in 2023.

▪ Absence of Washington excess deferred income tax settlement of $1.1 million.

▪ A 2.4 percent decrease in retail sales volumes to residential and commercial customer classes, offset in part by weather normalization and decoupling mechanisms of $4.2 million in certain jurisdictions.

◦ Partially offset by:

▪ Rate relief of $14.1 million primarily in North Dakota and South Dakota.

▪ Higher conservation revenues of $4.1 million that were offset in expense, as described below.

▪ Higher transportation volumes of $3.1 million due to 2.2 percent higher volumes, largely higher industrial customers, offset by lower electric generation.

▪ Decrease in Oregon natural gas cost sharing of $1.7 million.

• Purchased natural gas sold decreased $105.8 million, largely due to lower commodity costs of $130.2 million and lower volumes of natural gas purchased of $23.6 million.

These decreases were partially offset by net environmental compliance costs and emission allowance sales revenue of $48.0 million.

• Operation and maintenance increased $11.5 million.

◦ Primarily due to:

▪ Higher conservation-related costs of $4.1 million which are recovered in rates, as discussed above.

▪ Higher contract services of $3.5 million, primarily due to consulting and legal fees largely related to rate case filings, and higher subcontractor payments.

▪ Higher payroll and benefit-related costs of $3.2 million.

▪ Higher software related expenses of $1.8 million.

• Depreciation and amortization increased $6.7 million, primarily resulting from growth and replacement projects placed in service.

• Taxes, other than income increased $800,000, primarily from higher payroll taxes of $1.0 million and higher property taxes of $500,000, partially offset by lower revenue-based taxes of $700,000, which are recovered in rates.

• Other income increased $4.7 million.

◦ Due to higher interest income of $5.4 million, largely due to:

▪ Higher interest on regulatory deferral balances.

▪ Higher interest income associated with RNG projects of $2.2 million.

◦ Partially offset by higher pension expense of $1.1 million.

• Interest expense increased $5.6 million, primarily from higher long-term debt balances from debt issued in 2023 and 2024 and higher commercial paper and revolving credit agreement balances, partially offset by lower short-term debt due to short term debt repayments.

• Income tax expense increased $1.1 million largely the result of permanent tax adjustments.

2023 compared to 2022 Natural gas distribution earnings increased $3.3 million as a result of:

Natural gas distribution earnings increased $9.2 million as a result of:

• Revenue increased $82.4 million.

◦ Largely from:

▪ Rate relief of $7.9 million in Idaho and Washington, including the excess deferred income tax tariff settlement of $1.1 million in Washington.

▪ Increased revenue-based taxes recovered in rates of $6.1 million that were offset in expense, as described below.

▪ Higher basic service charges of $4.7 million.

▪ Higher transportation revenue of $3.8 million due to 13.5 percent higher volumes, largely higher electric generation.

▪ Approved rate recovery of short-term debt interest expense related to increased gas costs in Idaho of $3.2 million.

▪ Higher nonregulated revenue of $1.7 million, largely higher liquefied natural gas sales.

▪ Recovery of COVID-19 response costs, including bill assistance programs and waived late payment fees, in Oregon of

• Partially offset by:

◦ Lower purchased gas sold of $10.8 million, recovered in customer rates that was offset in expense, as described below.

◦ A 6.6 percent decrease in retail sales volumes to all customer classes, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.

• Purchased natural gas sold decreased $11.0 million, primarily due to lower volumes of natural gas purchased of $59.8 million, largely offset by higher natural gas costs of $48.7 million as a result of higher market prices.

Purchased natural gas sold includes the absence of the prior year disallowance of $845,000 ordered by the MNPUC.

MDU Resources Group, Inc.

◦ Primarily due to:

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

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

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

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

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

▪ Higher retail sales volumes of $2.0 million, which includes weather normalization and decoupling mechanism in certain jurisdictions, and higher volumes to commercial customer classes.

This increase was largely offset by lower volumes to residential customer classes, largely due to warmer weather in certain jurisdictions.

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

• Operation and maintenance increased $10.0 million.

◦ Largely due to:

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

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

▪ Higher insurance expense.

▪ Higher payroll-related costs of $1.5 million.

▪ Higher software related expenses of $1.3 million.

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

The transition services are expected to be complete as of March 2026.

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

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

• Other income decreased $9.7 million.

◦ Primarily due to:

▪ Higher payroll-related costs of $12.6 million, primarily higher employee incentive accruals and straight-time payroll.

▪ Increased uncollectible accounts expense of $1.6 million, largely due to higher revenue.

▪ Higher insurance expense of $1.0 million.

▪ Higher software related expenses of $900,000.

◦ Partially offset by:

▪ Lower contract services of $1.2 million, largely lower subcontract labor and consulting fees.

▪ Decreased other expenses, including regulatory deferrals, miscellaneous employee expenses, and gain on sale of the Company's customer service center.

• Depreciation and amortization increased $5.9 million, primarily resulting from growth and replacement projects placed in service.

• Taxes, other than income increased $4.1 million, largely from higher revenue-based taxes of $6.1 million which are recovered in rates, partially offset by lower property taxes due to lower assessed values of $2.3 million.

• Other income increased $17.5 million.

▪ Higher interest income of $11.3 million, largely related to purchased gas costs.

▪ Higher returns on the Company's nonqualified benefit plans of $6.9 million, as discussed in Note 9.

◦ Offset in part by higher pension and postretirement expense.

• Interest expense increased $15.4 million, primarily from higher short-term and long-term debt balances from debt issued in 2023 and 2022 and higher interest rates, partially offset by higher AFUDC debt of $2.6 million, due to higher rates.

• Income tax expense decreased $900,000 largely the result of higher permanent tax adjustments, partially offset by higher income before income taxes.

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.

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

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

▪ Higher pension expense of $1.4 million.

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

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

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

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

46 MDU Resources Group, Inc.

Outlook In 2025, the utility business experienced rate base growth of 16.0 percent, which includes the purchase of its ownership stake in Badger Wind Farm.

These segments grew rate base by 8.7 percent annually over the last five years on a compound basis and expects to invest approximately $2.5 billion of capital expenditures over the next five years.

Operations are spread across eight states where the Company expects customer growth to be higher than the national average.

3 unchanged sentences

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.

In May 2022, the Company began construction of Heskett Unit 4, an 88-MW simple-cycle natural gas-fired combustion turbine peaking unit at the existing Heskett Station near Mandan, North Dakota.

Heskett Unit 4 was in service and fully operational in July 2024.

Existing and proposed emissions reduction plans from the EPA could require the owners of Coyote Station to incur significant new costs.

The EPA's GHG and mercury emissions standards finalized in May 2024 would require additional pollution controls to operate beyond 2031 and 2027, respectively, with a potential extension to add pollution controls that may be granted.

If the owners decide to incur such costs, the 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.

On December 2, 2024, the EPA issued a final decision on the NDDEQ's 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 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 Court of Appeals on January 31, 2025, challenging EPA's NDDEQ state plan disapproval, and filed a petition for reconsideration with the EPA on February 6, 2025.

Although changes in the price of natural gas are passed through to customers and have minimal impact on the Company's earnings, the natural gas distribution segment's customers may benefit through the Company's utilization of storage and fixed price contracts to help manage price volatility.

The EPA's GHG and mercury emissions standards finalized in May 2024 would have required additional pollution controls for Coyote Station to operate beyond 2031 and 2027, respectively.

In April 2025, the EPA granted a two year extension for Coyote Station to add pollution controls to comply with the mercury emissions standard.

In June 2025, the EPA proposed rules to repeal both the mercury emissions standard and the electric generation GHG emissions standard.

If the rules go into effect, it could require owners of Coyote station to incur significant new costs.

These costs could, dependent on determination by state regulatory commissions on approval to recover such costs from customers, negatively impact the Company's results of operations, financial position and cash flows.

In December 2024, the EPA issued a final decision on the NDDEQ's Regional Haze state implementation plan, maintaining the proposed disapproval of the state's conclusion that no additional controls are warranted during this implementation period.

The EPA did not issue a federal implementation plan in place of the state plan and would have two years from the state plan disapproval to either propose a federal plan or approve a new state plan.

Coyote Station co-owners filed a petition for review with the Eighth Circuit in January 2025, challenging EPA's NDDEQ state plan disapproval, and in February 2025, filed a petition for reconsideration with the EPA, which was granted in April 2025.

In June 2025, the Eighth Circuit granted a request by the EPA to continue to hold the petition of review proceeding in abeyance so that the EPA could review the previous administration's findings and actions.

In March 2025, the EPA announced the agency is restructuring the regulations for implementing the Regional Haze Program.

Further, in October 2025, the EPA released an advanced notice of proposed rulemaking seeking input on restructuring the program with the intent to streamline regulatory requirements for states' visibility improvement obligations.

The Company is one of four owners of Coyote Station and cannot make a unilateral decision on the plant's future;

1 unchanged sentence

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.

40 MDU Resources Group, Inc.

On March 4, 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota under an interim electric service agreement approved by the NDPSC, and on June 6, 2023, the NDPSC unanimously approved the Company's electric service agreement request.

At full capacity, the data center requires 180 megawatts of electricity, which is the equivalent of about 28 percent of the Company's generation portfolio.

In December 2025, the Company completed the acquisition of a 49 percent ownership interest in Badger Wind Farm and placed the asset in service.

The completed transaction secures 122.5 MW of the project's total 250 MW generation capacity for the Company and follows the NDPSC's Advance Determination of Prudence and Certificate of Public Convenience and Necessity approvals, confirming the project is a prudent, cost-effective investment for customers.

The Company previously executed a PPA for 150 MW of output from the project, which included the option to purchase the 49 percent ownership interest.

With the closing now complete, the PPA has been reduced to 27.5 MW.

In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota.

At full capacity, the data center requires 180 MW of electricity, which is the equivalent of about 21 percent of the Company's generation portfolio.

Applied Digital's load is purchased from the MISO market and does not impact other customers' power supply.

On October 2, 2023, the Company filed with the NDPSC an electric service agreement request to serve an additional 225 megawatt data center load with Applied Digital in its service territory, which was approved on May 23, 2024.

On September 5, 2024, the Company filed an amendment to the electric service agreement previously approved by the NDPSC, increasing the service provided from 225 megawatts to 350 megawatts, which was approved on February 5, 2025.

A portion of the additional data center load is expected to be online in 2025.

On August 5, 2024, the Company filed a request with the SDPUC seeking approval on an electric service agreement to provide up to 50 megawatts of electricity to a data center near Leola, South Dakota.

Construction on the data center is scheduled to begin in the spring of 2025, pending delays due to the development of new local siting requirements for the data center.

The Infrastructure Investment and Jobs Act, commonly known as the Bipartisan Infrastructure Law, was enacted in the fourth quarter of 2021 and is providing long-term opportunities by designating funds for investments such as upgrades to electric and grid infrastructure, transportation systems, and electric vehicle infrastructure.

In addition, the IRA provides $369 billion in new funding for clean energy programs.

These programs include new tax incentives for solar, battery storage and hydrogen development along with funding to expand the production of electric vehicles and the build out of infrastructure to support electric vehicles.

The Company is pursuing various opportunities under the Grid Resilience and Innovative Partnerships Program, which is a part of the Infrastructure Investment and Jobs Act, and is also pursuing a biogas property at the Knott Landfill site in Bend, Oregon which may qualify for an investment tax credit and clean fuel production credits as part of the IRA.

The Company will continue to monitor additional opportunities from these legislative items.

An electric service agreement to serve an additional 350 MW data center load with Applied Digital in the Company's service territory was approved by the NDPSC.

100 MW of the additional data center load is expected to be fully online in the second quarter of 2026.

In August 2024, the Company filed a request with the SDPUC seeking approval on an electric service agreement to provide up to 50 MW of electricity to a data center near Leola, South Dakota.

Construction of the data center and approval of the electric service agreement which had been pending development of new local siting requirements for data center loads by McPherson County in South Dakota, were effective August 5, 2025.

Approval of the electric service agreement with the SDPUC is still pending filing an updated conditional use permit for the data center siting with McPherson County.

MDU Resources Group, Inc.

The Infrastructure Investment and Jobs Act, commonly known as the Bipartisan Infrastructure Law, was enacted in the fourth quarter of 2021 designating funds for investments such as upgrades to electric and grid infrastructure, transportation systems, and electric vehicle infrastructure.

In July 2025, the North Dakota Industrial Commission awarded the Company a grant award under the Grid Resilience and Innovative Partnerships Program, which is part of the Infrastructure Investment and Jobs Act.

The funds from the award will be used by the Company to build a 46 kV transmission line that will connect the Merricourt Transmission Substation to a 46 kV line near Fredonia, North Dakota.

In addition, the IRA provided new funding for clean energy programs.

The Company continues to pursue various opportunities under the Grid Resilience and Innovative Partnerships Program, and is also pursuing a biogas property at the Knott Landfill site in Bend, Oregon which may qualify for an investment tax credit and clean fuel production credits as part of the IRA.

As discussed previously, the Company has evaluated the OBBBA and does not expect a material impact as a result of this legislation.

Legislation and rulemaking The Company continues to monitor legislation and rulemaking related to clean energy standards that may impact its segments.

1 unchanged sentence

• 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.

The Electric Generation and Greenhouse Gas Rule establishes GHG emissions standards for new natural gas-fired electric generating units and existing coal units.

It is anticipated this rule could affect Montana-Dakota’s jointly owned coal-fired units.

The joint owners continue to evaluate compliance options.

This rule is currently being challenged before the DC Circuit Court.

Montana-Dakota is participating in this challenge.

Though the case has been fully briefed and oral argument has taken place, the EPA has requested the court hold the case in abeyance in order to allow new leadership to review the underlying rule, which was granted by the court on February 19, 2025.

The Mercury and Air Toxics Standards Rule tightens mercury emissions and non-mercury metals emissions standards for coal-fired generation facilities.

The stricter mercury emissions limit for lignite-fired units will require Coyote Station to increase existing emission controls.

In addition, Big Stone Station and Coyote Station must install particulate matter continuous emissions monitoring systems to monitor compliance with the revised non-mercury metals emission standard.

Compliance with the revised emission standards and monitoring requirements must be demonstrated by May 7, 2027.

This rule is likewise being challenged in the DC Circuit Court.

The Legacy Coal Combustion Residuals Rule requires utilities to evaluate older coal ash disposal units at certain inactive and active electric generating facilities.

Montana-Dakota must complete facility evaluations by February 8, 2027, to determine if legacy ash is present and assess the extent of ash on site.

If legacy ash is present, Montana-Dakota must monitor and evaluate for potential impacts and may need to conduct additional closure and remediation.

The cost of additional remediation or closure activities may be material.

This rule also faces challenge in the DC Circuit Court.

The fourth rule, the Effluent Limitations Guidelines Rule is not expected to have impacts on any owned or co-owned Montana-Dakota facilities.

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.

On January 20, 2025, President Trump released an Executive Order "Unleashing American Energy" that may impact these rules as it requires federal agencies within 30 days to review rules that potentially burden the development of domestic energy resources, and develop and implement action plans to suspend, revise or rescind the rules.

• In Oregon, the Climate Protection Program Rule was approved in December 2021, which required natural gas companies to significantly reduce GHG emissions from customer use of natural gas starting in 2022.

This rule was ultimately invalidated due to a procedural issue by the Oregon Court of Appeals, with final judgement issued in February 28, 2024.

MDU Resources Group, Inc.

On July 30, 2024, the ODEQ released the proposed new Climate Protection Program Rule.

On November 21, 2024, the Oregon Environmental Quality Commission adopted the new Climate Protection Program Rule.

Like the prior rule, natural gas companies are required to significantly reduce GHG emissions 50 percent below the baseline by 2035 and 90 percent below the baseline by 2050.

Each year, ODEQ will distribute compliance instruments to the Company at no cost and will decline annually in step with the reduction from baseline.

The first compliance period is three years, from 2025 to 2027, with compliance demonstrations required by December 9 of the year following the end of a compliance period.

Compliance periods are two years in length thereafter.

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 purchasing low carbon fuels such as RNG.

Cascade is evaluating customer bill impacts from the new rule.

Cascade began incurring expenses in 2022 to comply with the prior Climate Protection Program Rule.

The OPUC has authorized Cascade, through a deferred accounting order, to collect $4.2 million in actual 2022 and 2023 costs related to the prior Climate Protection Program Rule.

The average residential customer will experience a monthly bill increase of $1.75 or 2.4 percent.

Cascade also expects the compliance costs for the new Climate Protection Program Rule to be recovered through customer rates.

On August 30, 2024, the Company filed a request for reauthorization of the use of deferred accounting for costs related to the decarbonization programs in Oregon.

In March 2025, the EPA announced reconsideration of the Electric Generation and Greenhouse Gas Rule, Mercury and Air Toxics Standards Rule, and Effluent Limitations Guidelines Rule.

Comments on certain of these proposed rules were due in August 2025.

If the rules were to remain as originally proposed and if the costs to comply with these rules are not fully recoverable from customers, they could have a material adverse effect on the Company's results of operations and cash flows.

• In February 2026, the EPA published a final rule that rescinded the 2009 Endangerment Finding and related standards for motor vehicle GHG emissions under the Clean Air Act.

The final rule does not directly address or repeal GHG regulations for power plants and other non-motor vehicle sources.

The Company is currently evaluating this rulemaking.

• In July 2024, the ODEQ published its proposed rules to create a new Climate Protection Program.

The Oregon Environmental Quality Commission adopted the rules in November 2024.

The Company intends to meet its obligations first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG.

Compliance costs for these regulations are being recovered through customer rates.

Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow.

For more information about this rule and associated compliance costs, see Items 1 and 2 - Business Properties.

• In Washington, the Climate Commitment Act requires natural gas distribution companies to reduce overall GHG emissions 45 percent below 1990 levels by 2030, 70 percent below 1990 levels by 2040 and 95 percent below 1990 levels by 2050.

The Company must demonstrate that it has met GHG emissions reduction goals through a combination of on-site emissions reductions and the use of approved allowances and offsets.

Some emissions allowances are allocated by the Washington DOE to the Company at no cost and a portion of these are required to be sold at auction to generate revenue for the benefit of customers.

The Company expects compliance costs for these regulations will be recovered through customer rates.

It is projected customer bills could increase substantially as a result of the legislation.

The WUTC has approved Cascade’s request for a deferred accounting order, which will allow Cascade to collect $20.6 million in compliance costs within a ten month recovery period from June 1, 2024 through March 31, 2025.

• 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.

For more information about this rule and associated compliance costs, see Items 1 and 2 - Business Properties.

• The Washington SBCC on November 28, 2023 and December 12, 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 multifamily buildings and proposed the review of similar restrictions in the future for residential buildings.

These amendments came after previous, similar state building code amendments were stayed by the SBCC after legal challenge by Cascade, along with two other local natural gas distribution companies in Washington and a coalition of homeowners, builders, and suppliers.

Cascade did not believe such revisions addressed the issues which existed in the initial amendments.

On May 15, 2024, the Company filed a joint complaint seeking declaratory and injunctive relief under federal law against the Washington SBCC's adoption of the Washington State Energy Code.

• The Washington SBCC in 2023 adopted residential and commercial building code amendments that will significantly limit the use of natural gas for space and water heating in new and retrofitted commercial and residential buildings.

In May 2024, the Company filed a joint complaint seeking declaratory and injunctive relief under federal law against the Washington SBCC's adoption of the amended Washington State Energy Code.

This complaint was dismissed by the federal district court.

Petitioners have appealed this decision to the United States Court of Appeals for the Ninth Circuit.

The Company's opening brief was filed in July 2025.

Oral argument before a three-judge panel of the Ninth Circuit was held on February 10, 2026.

Initiative Measure No.

2066, which was approved by voters, prohibits the Washington State Energy Code from "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." It is being challenged in the King County Superior Court.

The Building Association of Washington is concurrently litigating to enforce SBCC compliance with the initiative and is also active in the legal defense of Initiative Measure No.

2066 from activist litigation.

• On March 6, 2024, the SEC issued Final Rule 33-11275 - The Enhancement and Standardization of Climate-Related Disclosures for Investors.

This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions.

The rule requires implementation in phases between 2025 and 2033.

2066, which was approved by voters, does not allow the Washington State Energy Code to "in any way prohibit, penalize, or discourage the use of gas for any form of heating, or for uses related to any appliance or equipment, in any building." In May 2025, the King County Superior Court filed an order ruling Initiative Measure No.

2066 unconstitutional.

Following the ruling, the Building Industry Association of Washington filed a notice of appeal with the King County Superior Court.

The King County Superior Court’s order invalidating Initiative Measure No.

2066 is now pending review by the Washington State Supreme Court.

The Court heard oral arguments in the case in January 2026.

48 MDU Resources Group, Inc.

• In March 2024, the SEC issued Final Rule 33-11275 - The Enhancement and Standardization of Climate-Related Disclosures for Investors.

In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review.

The Company is evaluating the rule.

In March 2025, the SEC withdrew its defense of the rules.

In July 2025, the SEC asked the Eighth Circuit to issue a ruling on the abandoned climate regulations.

In September 2025, the Eighth Circuit stated it was pausing its consideration of legal challenges against this rule, pending further action by the SEC.

MDU Resources Group, Inc.

Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in Items 1 and 2 - Business Properties.

Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in Item 1 - Business.

The segment focuses on utilizing its extensive expertise in the design, construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of existing operations, organic growth and investments in energy-related assets within or in close proximity to its current operating areas.

4 unchanged sentences

In support of this strategy, the Company completed the following growth projects in 2024 and 2025:

• In November 2023, the Grasslands South Expansion project was placed in service.

The project increased system capacity by 94 MMcf of natural gas per day.

• In November 2023, the Line Section 15 Expansion project was placed in service and increased system capacity by 25 MMcf of natural gas per day.

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

2 unchanged sentences

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

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

The segment is exposed to natural gas and oil price volatility including fluctuations in basis differentials.

4 unchanged sentences

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.

1 unchanged sentence

The Company is partially mitigating these challenges by planning for extended lead times further in advance.

The segment is currently experiencing inflationary pressures with increased raw material and contract services costs.

The Company expects supply chain challenges and inflationary pressures to continue.

The Company expects these delays to continue.

Inflationary pressures have moderated, but costs for raw material and contract services remain high.

For additional discussion regarding risks and uncertainties, see Item 1A - Risk Factors.

The segment focuses on the recruitment and retention of a skilled workforce to remain competitive and provide services to its customers.

31 unchanged sentences

End of period 37.6 44.1 37.7

2024 compared to 2023 Pipeline earnings increased $21.1 million as a result of:

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

• Revenues increased $17.4 million.

◦ Driven by increased transportation volumes, largely due to:

▪ Increased transportation volumes and demand revenue from growth projects placed in service in November 2023 and throughout 2024 of $19.8 million.

◦ Higher storage-related revenues of $7.1 million.

◦ New transportation and storage rates effective August 1, 2023 of $6.7 million.

◦ Partially offsetting these increases was an expired negotiated contract converted to tariff rate.

◦ Increased demand revenue, largely due to:

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

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

▪ Partially offset by the expiration of certain contracts.

◦ Higher interruptible transportation revenue of $1.3 million.

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

• Operation and maintenance increased $6.1 million.

1 unchanged sentence

▪ Higher payroll-related costs of $2.3 million.

▪ Higher materials, contract services and pipeline safety fees.

◦ Partially offset by lower legal and consulting costs, due to absence of rate case related expenses.

• Depreciation and amortization increased $2.6 million due to higher plant balances associated with growth projects placed in-service, as previously discussed, partially offset by fully depreciated assets.

• Taxes, other than income increased $1.4 million, largely resulting from higher property taxes in Montana and North Dakota.

• Other income increased $2.6 million, primarily due to:

◦ Proceeds received from a customer settlement of $2.0 million.

◦ Higher interest income of $700,000.

• Interest expense in continuing operations increased $2.2 million, resulting from higher debt balances to fund capital expenditures, as previously discussed, partially offset by lower average debt rates.

• Income tax expense in continuing operations increased $5.1 million, largely due to higher income before income taxes, partially offset by a decrease in the state effective rate largely due to growth in North Dakota.

44 MDU Resources Group, Inc.

2023 compared to 2022 Pipeline earnings increased $11.6 million as a result of:

• Revenues increased $22.0 million.

◦ Driven by increased transportation volume revenues, largely due to:

▪ Increased contracted volume commitments and a full year of benefit from the North Bakken Expansion project of $9.9 million.

▪ Increased transportation volumes and demand revenue from other organic growth projects placed in service in November 2023 and August 2022.

◦ New rates effective August 1, 2023, of $5.0 million.

◦ Higher storage-related revenues

◦ Higher non-regulated project revenues of $2.6 million.

◦ Partially offsetting these increases was the non-renewal of certain contracts.

• Operation and maintenance increased $9.9 million.

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

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

The transition services are expected to be complete as of March 2026.

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

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

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

• Other income decreased $2.8 million.

◦ Primarily due to:

▪ Higher payroll-related costs of $6.9 million, largely related to lower incentive accruals and benefit-related costs.

▪ Higher non-regulated project costs of $1.2 million directly associated with higher non-regulated project revenues, as previously discussed.

▪ Higher contract services and insurance costs.

• Depreciation and amortization decreased $100,000 due to fully depreciated plant, largely offset by higher plant balances associated with growth projects placed in-service, as previously discussed.

• Taxes, other than income decreased $1.5 million, largely resulting from lower property taxes in Montana.

• Other income increased $2.6 million, primarily due to:

◦ Higher returns on the Company's nonqualified benefit plan investments, as discussed in Note 9.

◦ Higher AFUDC of $800,000 for the construction of the company's growth projects.

• Interest expense in continuing operations increased $3.2 million, resulting from higher average interest rates and higher debt balances to fund capital expenditures, partially offset by higher AFUDC, as previously discussed.

• Income tax expense in continuing operations increased $1.9 million, largely due to higher income before income taxes, partially offset by permanent tax adjustments.

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

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

MDU Resources Group, Inc.

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

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

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

Outlook The Company has continued to experience the effect of associated natural gas production in the Bakken, which has provided opportunities for organic growth projects and increased transportation demand.

The completion of organic growth projects has contributed to higher volumes of natural gas the Company transports through its system.

Bakken natural gas production is currently at or near record levels and the outlook remains positive with continued growth expected due to new oil wells and increasing gas to oil ratios.

Bakken natural gas production is currently at or near record levels and the outlook remains positive with continued growth expected due to increasing gas to oil ratios which may moderate recent decreases in drilling activity.

Increases in national and global natural gas supply have moderated pressure on natural gas prices and price volatility.

1 unchanged sentence

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.

In 2024, the EPA published several final rules related to GHG emissions from the oil and natural gas industry.

These rules update, strengthen and expand standards to reduce GHG emissions and other air pollutants from new and existing oil and gas facilities, revise the GHG reporting rules to improve the monitoring, measurement, calculation and reporting of GHG data, and incorporate the Waste Emissions Charge provisions from the IRA.

The Company continues 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 growth opportunities through organic projects in all areas in which it operates, which includes additional projects with local distribution companies, Bakken area producers, electric generation customers and industrial customers in various stages of development, including:

• Signed agreements for an expansion project, to serve a new electric generation facility in northwest North Dakota, with a targeted in-service date of late 2028.

• Potential Bakken East Pipeline project, which could consist of 375 miles of pipeline construction from western North Dakota to the eastern part of the state.

A non-binding open season for the project concluded on January 31, 2025.

The Company is currently evaluating the results.

GHG emissions regulations continue to evolve due to congressional actions and agency reconsideration.

Methane Waste Emissions Charge regulations finalized in 2024 were eliminated by a resolution of disapproval passed by Congress and signed by the President in March 2025.

The OBBBA postponed the Waste Emissions Charge provisions in the Clean Air Act to 2034.

The EPA has issued several actions since the EPA Administrator's announcement regarding 31 historic actions to advance the President's "Power the Great American Comeback", which include extending deadlines for certain oil and gas new source performance standards and a proposal to reconsider the Greenhouse Gas Reporting Program.

The Company continues to comply with rules as they remain in effect, and to monitor and assess these rulemaking changes and the potential impacts they may have on its business processes, current and future projects, results of operations and disclosures.

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

• Line Section 32 Expansion Project which will provide natural gas transportation service to a new electric generation facility in northwest North Dakota.

The project consists of approximately 20 miles of pipe and ancillary facilities and is designed to increase natural gas transportation capacity by 190 MMcf per day, which is supported by a long-term customer agreement.

The Company continues to make progress on required surveys and anticipates filing its FERC application in March 2026.

The project is dependent on regulatory approvals and is targeted to be in service in late 2028.

• Potential Bakken East Pipeline Project, which could consist of 350 miles of pipeline construction from western North Dakota to the eastern part of the state, plus additional pipeline laterals.

The Company continues actively marketing the project and began a binding open season on February 2, 2026, which will conclude on March 13, 2026.

The results of the open season will be evaluated to determine the final design, timeline and project cost.

In 2025, the Company began working with landowners to conduct environmental and civil surveys along the potential route and plans to continue survey work in the spring of 2026 when weather conditions allow.

In August 2025, the North Dakota Industrial Commission selected the project for firm capacity commitments of up to $50 million annually for 10 years.

• Potential Minot Industrial Pipeline Project, which could consist of an approximately 90-mile pipeline from Tioga, North Dakota to Minot, North Dakota and ancillary facilities.

The Company has signed an agreement to support the early stage development of the project through the second quarter of 2026.

The project would provide incremental natural gas transportation capacity for anticipated industrial demand.

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

9 unchanged sentences

Total operating expenses .5 15.9 29.4 (96.9) % (45.9) %

Operating loss (15.7) (29.2) (26.2) (46) % 11 %

Operating income (loss) .2 (15.7) (29.2) 101.3 % (46.2) %

Gain on tax-free exchange of retained shares in Knife River

— — 186.6 — % (100.0) %

Other income (expense) 16.6 16.4 (1.3) 1 % NM

Interest expense 15.0 19.3 .5 (22) % NM

Income (loss) before income taxes (14.1) 154.5 (28.0) (109) % NM

Other income 6.6 16.6 16.4 (60.2) % 1.2 %

Interest expense 4.9 15.0 19.3 (67.3) % (22.3) %

Income (loss) before income taxes 1.9 (14.1) 154.5 113.5 % (109.1) %

Income tax benefit (.3) (5.5) (8.1) (94.5) % (32.1) %

Income (loss) from continuing operations

(8.6) 162.6 (21.2) (105) % NM

2.2 (8.6) 162.6 125.6 % (105.3) %

Discontinued operations, net of tax

1 unchanged sentence

Net income $ 1.2 $ 91.4 $ 247.7 (98.7) % (63.1) %

NM - not meaningful

The Company completed the separations of Knife River, its former construction materials and contracting segment, on May 31, 2023 and Everus, its former construction services segment, on October 31, 2024, into new independent publicly-traded companies.

1 unchanged sentence

Also included in discontinued operations are certain strategic initiative costs associated with the separations of Knife River and Everus.

Other includes activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023, as well as corporate overhead costs paid by Everus and Knife River for those respective periods which were allocated to the Company's remaining segments in 2025.

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

Other earnings decreased by $156.3 million from 2023, primarily due to the absence of the Company's 2023 gain of $186.6 million related to the tax-free exchange of its retained shares in Knife River.

Other also benefited from higher income from discontinued operations, as well as lower interest expense due to lower borrowings associated with funding strategic initiatives.

For the full year, Other reported net income of $1.2 million compared to net income of $91.4 million for 2024.

The decrease was primarily due to the absence of the income from discontinued operations in 2025.

Intersegment Transactions

7 unchanged sentences

Purchased natural gas sold $ 74.8 $ 68.9 $ 62.1

$ 15.4 $ 13.6 $ 0.6

Other income $ 5.2 $ 15.4 $ 13.6

Interest expense $ 5.2 $ 15.4 $ 13.6

$ 15.4 $ 13.6 $ 0.6

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

4 unchanged sentences

credit facilities and commercial paper of the Company and its subsidiaries, as described in Capital resources;

and issuance of debt and equity securities if necessary.

and issuance of debt securities and equity securities using the Company's FSA and ATM program as needed.

Years ended December 31, 2025 2024 2023

4 unchanged sentences

Financing activities 268.8 40.3 204.6

(Decrease) increase in cash, cash equivalents and restricted cash (10.1) (3.5) 26.3

Decrease in cash, cash equivalents and restricted cash (38.7) (10.1) (3.5)

Cash, cash equivalents and restricted cash -- beginning of year 66.9 77.0 80.5

14 unchanged sentences

Net cash provided by continuing operations 474.1 411.8 305.3 62.3 106.5

Net cash provided by discontinued operations 90.5 27.3 188.4 63.2 (161.1)

Net cash (used in) provided by discontinued operations (.7) 90.5 27.3 (91.2) 63.2

Net cash provided by operating activities $ 473.4 $ 502.3 $ 332.6 $ (28.9) $ 169.7

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

The increase in cash flows provided by operating activities in 2024 from 2023 was largely driven by an increase in cash from other current assets, primarily the collection of purchased gas cost and fuel cost adjustment balances at the natural gas distribution and electric businesses.

Also contributing was lower cash used in accounts payable, primarily related to the payment of natural gas costs at the natural gas distribution business, and higher cash provided by discontinued operations in 2024.

Partially offsetting these items was a decrease of cash from accounts receivable, largely due to lower gas costs in 2024 compared to 2023 at the natural gas distribution business.

The decrease in cash flows provided by operating activities in 2023 from 2022 was largely driven by the payment of increased natural gas costs and the purchase/sale of environmental allowances in 2023, as discussed in Note 7, all at the natural gas distribution business.

Also contributing were lower cash provided by discontinued operations, primarily cash used at Knife River in the five months of 2023 compared to cash provided by Knife River in the twelve months of 2022 and higher costs incurred in 2023 associated with the Knife River separation.

Partially offsetting these items was higher cash from receivables due to the timing of collection of accounts receivable from customers at the natural gas distribution business.

The decrease in cash flows provided by operating activities in 2025 from 2024 was largely driven by the absence of cash provided by discontinued operations in 2024, as well as the absence of certain fuel cost recoveries in 2025 and increases in certain regulatory cost deferrals.

Partially offsetting the decrease was higher collection of accounts receivable associated with higher gas costs in December 2024, lower cash used for payment of other current liabilities, including compliance costs, accrued compensation, data center customer deposits, and net environmental compliance costs, all at the natural gas distribution business.

54 MDU Resources Group, Inc.

6 unchanged sentences

Investments (4.2) (5.2) (2.4) 1.0 (2.8)

Proceeds from investment cost basis withdrawal 9.0 20.0 — (11.0) 20.0

Proceeds from investment excess cash and cost basis withdrawal 5.0 9.0 20.0 (4.0) (11.0)

Net cash used in continuing operations (780.9) (523.8) (465.1) (257.1) (58.7)

1 unchanged sentence

Net cash used in investing activities $ (780.9) $ (552.7) $ (540.7) $ (228.2) $ (12.0)

The increase in cash used in investing activities in 2024 from 2023 was primarily due to higher capital expenditures at the natural gas distribution business, increased capital expenditures at the pipeline businesses for its expansion projects and lower receipt of proceeds from the withdrawal of cost basis from insurance policies in 2024 than in 2023.

This was largely offset by lower cash used in discontinued operations due to activity for Everus for ten months in 2024 compared to the full year in 2023 and Knife River activity for five months in 2023.

The decrease in cash used in investing activities in 2023 from 2022 was primarily the result of lower cash used in discontinued operations due to Knife River activity in the five months of 2023 versus twelve months of 2022, the receipt of proceeds from the withdrawal of cost basis from insurance policies in 2023, and the absence of 2022 plant removal costs at the electric business.

This was partially offset by higher capital expenditures at the pipeline business for its expansion projects and increased capital expenditures at the natural gas distribution business, primarily higher natural gas distribution system improvements related to increased capacity, largely offset by lower capital expenditures for electric production and transmission projects.

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

Partially offsetting this was the absence of cash used in discontinued operations with the spinoff of Everus.

Financing activities

10 unchanged sentences

Tax withholding on stock-based compensation (4.5) (2.6) (3.1) (1.9) .5

Net cash (used in) provided by continuing operations (76.6) 230.2 (2.8) (306.8) 233.0

Net cash provided by (used in) continuing operations 268.8 (76.6) 230.2 345.4 (306.8)

Net cash provided by (used in) discontinued operations — 116.9 (25.6) (116.9) 142.5

Net cash provided by financing activities $ 268.8 $ 40.3 $ 204.6 $ 228.5 $ (164.3)

The decrease in cash provided by financing activities in 2024 from 2023 was primarily due to the absence of the 2023 issuance of short-term borrowings associated with the debt for equity exchange of the Knife River retained shares, as well as the absence of the 2023 issuance of short-term borrowings at the natural gas distribution business used to fund higher natural gas costs.

Further driving the decrease was lower issuance of long-term debt, primarily the absence of the 2023 issuances by the Company, largely used to replace the Centennial debt.

Partially offsetting these items was the absence of higher repayments in 2023 of long-term and short-term borrowings, as Centennial repaid all of its outstanding debt in the second quarter of 2023 due to the Knife River separation, and increased cash provided by discontinued operations.

In addition, lower dividends were paid in 2024 due to a change in the targeted dividend payout ratio after the Knife River separation.

The increase in cash provided by financing activities in 2023 from 2022 was primarily due to higher issuance of short-term borrowings associated with the debt for equity exchange of the Knife River retained shares, as well as the issuance of short-term borrowings at the natural gas distribution business to fund higher natural gas costs.

Also contributing was higher issuance of long-term debt at the Company to replace the Centennial debt repayment and to fund capital expenditures.

Partially offsetting the increase was higher repayments of short-term and long-term debt at the natural gas distribution businesses.

In addition, due to the Knife River separation, Centennial repaid all of its outstanding debt in the second quarter of 2023, which was facilitated by the Knife River repayment and the Company entering into various new debt instruments.

Refer to Note 3 for additional information related to the repayment of debt associated with the Knife River separation.

The variance of cash used in discontinued operations in 2023 compared to cash provided by discontinued operations in 2022 also contributed to the increase offset.

48 MDU Resources Group, Inc.

The increase in cash provided by financing activities in 2025 from 2024 was primarily due higher long-term debt issuance proceeds used to finance capital expenditure projects, primarily at the electric business.

Also contributing was the absence of 2024 short-term borrowing repayment at the natural gas distribution business.

Partially offsetting these items was the absence of cash provided by discontinued operations in 2024.

Defined benefit pension plans

4 unchanged sentences

For 2025, the Company assumed a long-term rate of return on its qualified defined pension plan assets of 6.5 percent.

Due to a difference between the actual and assumed long-term rate of return the Company experienced a decrease in the qualified defined pension plan assets.

Differences between actuarial assumptions and actual plan results are deferred and amortized into expense when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets.

Therefore, this change in asset values will be reflected in future expenses of the plans beginning in 2026.

The funded status of the plans improved $2.3 million from prior year, primarily from liability gains due to a higher discount rate.

At December 31, 2024, the pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $24.7 million.

Pretax pension expense reflected in the Consolidated Statements of Income for the year ended December 31, 2024 was $835,000.

Pretax pension income reflected in the Consolidated Statements of Income for the years ended December 31, 2023 and 2022, was $580,000 and $2.3 million, respectively.

The funded status of the plans improved $6.3 million from prior year, primarily due to increase in plan assets, as discussed previously.

At December 31, 2025, the pension plans' projected benefit obligations exceeded these plans' assets by approximately $18.5 million.

Pretax pension expense reflected in the Consolidated Statements of Income for the years ended

MDU Resources Group, Inc.

December 31, 2025 and 2024, was $3.4 million and $835,000, respectively.

Pretax pension income reflected in the Consolidated Statements of Income for the year ended December 31, 2023 was $580,000.

The Company's pension expense is currently projected to be approximately $4.7 million in 2026.

1 unchanged sentence

The Company expects to contribute the minimum funding requirement of $3.8 million in 2026.

For the year ended December 31, 2024, the Company contributed the minimum funding requirement of $2.9 million.

There were no minimum required contributions for the years ended December 31, 2023, or 2022 due to an additional contribution of $20.0 million in 2019, which created prefunding credits that were used in future periods.

For the years ended December 31, 2025 and 2024, the Company contributed the minimum funding requirement of $3.4 million and $2.9 million, respectively.

There were no minimum required contributions for the year ended December 31, 2023, due to an additional contribution of $20.0 million in 2019, which created prefunding credits that were used in future periods.

For more information on the Company's pension plans, see Item 8 - Note 15.

5 unchanged sentences

Capital expenditures:

Electric $ 134 $ 110 $ 116 $ 154 $ 494 $ 205

Electric $ 110 $ 116 $ 430 (d)

$ 158 $ 309 $ 250

Natural gas distribution 275 285 301 342 295 240

Pipeline 116 127 61 60 70 181

Total capital expenditures (a)(d)

Total capital expenditures (a)(e)

$ 501 $ 528 $ 792 $ 560 $ 674 $ 671

(a) Capital expenditures for 2022 and 2023 are reported as gross capital expenditures.

Capital expenditures for 2024, and estimated expenditures for 2025 through 2027 are reported on a net basis.

(a) Capital expenditures for 2023 are reported as gross capital expenditures.

Capital expenditures for 2024 and 2025 as well as estimated expenditures for 2026 through 2028 are reported on a net basis.

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

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

(d) Excludes Other category.

Planned utility investments in the Company's estimated capital expenditures for 2025 through 2027 include construction of electric transmission lines and substations, as well as natural gas delivery infrastructure, to serve a customer base that is expected to continue growing at 1 percent to 2 percent annually over the next five years, construction of JETx, power generation projects, and replace and modernize existing electric and natural gas utility infrastructure to ensure continued safe and reliable service to customers.

At the pipeline business, the Company will focus on system growth to expand natural gas transmission capacity.

A number of projects are included in the planned investments.

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

This amount was previously included in 2026 estimates.

(e) Excludes Other category.

Planned utility investments in the Company's estimated capital expenditures for 2026 through 2028 include system upgrades, substation improvements and generation projects, construction of JETx, system replacements, expansion and modernization projects to meet demand from a growing customer base, including new service extensions and capacity expansion to accommodate economic and population growth across the Company's eight-state territory.

The pipeline business will continue to evaluate customer-driven projects, including expansion projects, to serve power generation and industrial demand in the region.

In addition, the pipeline will focus on system maintenance and expanding capacity where market conditions support additional investment.

A number of projects are included in the planned investments as the Company continues to invest in safe, reliable and environmentally-responsible energy delivery infrastructure across its regulated businesses.

For more information on the Company's growth projects, see Business Segment Financial and Operating Data.

Other estimated capital expenditures for the years 2025 through 2027 include those for:

• System upgrades

• Routine replacements

• Service extensions

• RNG infrastructure projects

• Routine equipment maintenance and replacements

• Buildings, land and building improvements

• Pipeline and natural gas storage projects

• Transmission opportunities

• Environmental upgrades

• Other growth opportunities

MDU Resources Group, Inc.

The Company continues to evaluate potential future acquisitions and other growth opportunities that would be incremental to the outlined capital program;

1 unchanged sentence

The Company continuously monitors its capital expenditures for project delays and changes in economic viability and adjusts as necessary.

It is anticipated that all of the funds required for capital expenditures for the years 2025 through 2027 will be funded by various sources, including internally generated funds;

credit facilities and commercial paper of the Company and its subsidiaries, as described later;

and issuance of debt and equity securities if necessary.

It is anticipated that all of the funds required for capital expenditures for the years 2026 through 2028 will be funded by various sources, including equity issuance, debt financing and internally generated funds.

56 MDU Resources Group, Inc.

Capital resources

1 unchanged sentence

The primary sources of cash other than cash generated from operating activities are cash from revolving credit facilities, the issuance of long-term debt and the sale of equity securities.

Debt resources

Certain debt instruments of the Company and its subsidiaries contain restrictive and financial covenants and cross-default provisions.

In order to borrow under the respective debt agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at December 31, 2024.

Debt resources Certain debt instruments of the Company and its subsidiaries contain restrictive and financial covenants and cross-default provisions.

In order to borrow under the respective debt agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions.

Intermountain was not in compliance with its minimum interest coverage ratio for the period ended September 30, 2025, which constituted an event of default under the terms of the Intermountain NPAs.

In addition, the event of default under the terms of the Intermountain NPAs constituted a cross-default under the terms of certain NPAs of MDU Energy Capital and revolving credit agreements held by the Company and Intermountain.

Subsequent to September 30, 2025, Intermountain and MDU Energy Capital obtained waivers for this non-compliance from the holders of a majority of their respective outstanding notes, and Intermountain and the Company obtained waivers from the lenders of the revolving credit agreements, which collectively cured the impact of any events of default.

The Company and its subsidiaries were in compliance with applicable covenants at December 31, 2025.

In the event the Company or its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

As of December 31, 2025, the Company had investment grade credit ratings at all entities issuing debt which carried public ratings.

For more information on the covenants, certain other conditions and cross-default provisions, see Item 8 - Note 10.

Total equity as a percent of total capitalization was 54 percent at December 31, 2024 and 55 percent at December 31, 2023.

This ratio is calculated as the Company's total equity, divided by the Company's total capital.

Total capital is the Company's total debt, including debt in discontinued operations and including short-term borrowings and long-term debt due within 12 months, plus total equity.

Management believes this ratio is an indicator of how the Company is financing its operations, as well as its financial strength.

The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries at December 31, 2024:

Company Facility Facility

Limit Amount Outstanding Letters

of Credit Expiration

(In millions)

Montana-Dakota Utilities Co.

Commercial paper/Revolving credit agreement (a) $ 200.0 $ 81.4 $ — 10/18/28

Cascade Natural Gas Corporation

Revolving credit agreement

$ 175.0 (b) $ 64.6 $ 2.2 (c) 6/20/29

Intermountain Gas Company

Revolving credit agreement

$ 105.1 $ — 6/20/29

MDU Resources Group, Inc.

Revolving credit agreement

$ — $ 12.1 (c)

(a) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Montana-Dakota on stated conditions, up to a maximum of $250.0 million).

At December 31, 2024, there were no amounts outstanding under the revolving credit agreement.

(b) Certain provisions allow for increased borrowings, up to a maximum of $225.0 million.

(d) Certain provisions allow for increased borrowings, up to a maximum of $250.0 million.

Montana-Dakota On October 18, 2023, Montana-Dakota amended and restated its revolving credit agreement to increase the borrowing capacity to $200.0 million and extend the maturity date to October 18, 2028.

Montana-Dakota's revolving credit agreement supports its commercial paper program.

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 commercial paper and revolving credit agreement borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of certain operations of Montana-Dakota.

Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings.

The credit agreement contains customary covenants and provisions, including covenants of Montana-Dakota 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 limitations on the sale of certain assets and on the making of certain loans and investments.

On July 11, 2024, Montana-Dakota issued $125.0 million of senior notes under a note purchase agreement with maturity dates ranging from July 11, 2039 to July 11, 2054, at a weighted average interest rate of 5.96 percent.

The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to capitalization to be greater than 65 percent.

The covenants also include certain restrictions on the sale of certain assets, loans and investments.

Cascade On June 20, 2024, Cascade amended and restated its revolving credit agreement to increase the borrowing capacity from $100.0 million to $175.0 million and extend the maturity date to June 20, 2029.

Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of total debt to total capitalization 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.

50 MDU Resources Group, Inc.

On January 20, 2023, Cascade entered into a $150.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of January 19, 2024.

On December 5, 2023, Cascade paid down $100.0 million of the outstanding balance, with the final $50.0 million repayment made on January 19, 2024.

Intermountain On June 20, 2024, Intermountain amended and restated its revolving credit agreement to increase the borrowing capacity from $100.0 million to $175.0 million and extend the maturity date to June 20, 2029.

Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

The credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of total debt to total capitalization 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.

On January 20, 2023, Intermountain entered into a $125.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of January 19, 2024.

In March, April and May 2023, Intermountain paid down $20.0 million, $30.0 million and $30.0 million, respectively, of the outstanding balance, with the final $45.0 million repayment made on January 19, 2024.

MDU Resources Group, Inc.

On May 31, 2023, the Company entered into a $200.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2028.

Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

The credit agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent.

The covenants also include certain restrictions on the sale of certain assets, loans and investments.

On May 31, 2023, the Company entered into a $375.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2025.

On November 15, 2023, the Company paid down $185.0 million of this term loan.

On November 1, 2024, the Company repaid its remaining outstanding balance of $190.0 million and the term loan agreement subsequently terminated.

The Company's repayment was funded by the Everus repayment of debt in connection with the separation.

On May 31, 2023, the Company entered into a $150.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 29, 2024.

At December 31, 2023, the Company had no amount outstanding, which remained that way until this agreement matured and subsequently terminated in May 2024.

WBI Energy Transmission WBI Energy Transmission has a $350.0 million uncommitted note purchase and private shelf agreement with an expiration date of December 22, 2025.

WBI Energy Transmission had $235.0 million of notes outstanding at December 31, 2024, which reduced the remaining capacity under this uncommitted private shelf agreement to $115.0 million.

This agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent.

Other covenants include a limitation on priority debt, restrictions on the sale of certain assets and the making of certain investments.

On April 1, 2024, WBI Energy Transmission entered into a $60.0 million term loan agreement with an interest rate of 4.52 percent and a maturity date of April 1, 2039, with the principal to be repaid in equal annual installments of $4.0 million each, beginning March 2025 and continuing through the maturity date.

The agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent.

The covenants also include certain restrictions on the sale of certain assets, loans and investments.

For more information on the covenants, certain other conditions and cross-default provisions, outstanding revolving credit facilities, and new long-term debt issuances, see Item 8 - Note 9.

Equity offerings In August 2025, the Company entered into an EDA pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $400.0 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs.

Since the establishment of the ATM offering program, the Company did not issue common stock pursuant to the EDA nor enter into any FSAs related to the EDA.

On December 5, 2025, the Company completed a follow-on public offering of 10,152,284 of shares of the Company's common stock at a public offering price of $19.70 per share.

In addition, on December 23, 2025, the underwriters exercised their option to purchase 1,522,842 additional shares of the Company's common stock.

Pursuant to the FSAs entered into in connection with the offering, the Company has discretion to settle the FSAs on one or more settlement dates prior to December 6, 2027, subject to certain price adjustments as set forth in the FSAs as well as adjustments for transaction and other associated fees.

The FSAs will be physically settled with shares of common stock issued by the Company, unless the Company elects to settle the FSAs in net cash or net shares, subject to certain conditions.

If the Company elects to physically settle the FSAs, the Company will physically issue shares of common stock to the banking counterparties at the then-applicable forward sale price and receive proceeds at that time.

Actual cash proceeds, if any, for settlement of FSAs will depend on the method and timing the Company elects for settlement.

Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in the Company's diluted earnings per share calculation using the treasury stock method.

For more detailed information about the Company's equity transactions, see Item 8 - Note 11.

Dividend restrictions

2 unchanged sentences

Material cash requirements

For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see

Item 8 - Notes 10 and 21.

For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Item 8 - Notes 9 and 17.

At December 31, 2025, the Company's material cash requirements under these obligations were as follows:

30 unchanged sentences

As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised.

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

58 MDU Resources Group, Inc.

The Company performs its goodwill impairment testing annually in the fourth quarter.

8 unchanged sentences

For the years ended December 31, 2025, 2024, and 2023, there were no impairment losses recorded.

At October 31, 2024, the Company's annual impairment testing indicated there was no impairment at its natural gas distribution reporting unit or Everus, its former construction services reporting unit.

At October 31, 2025, the Company's annual impairment testing indicated there was no impairment at its natural gas distribution reporting unit.

The estimated fair value of the natural gas distribution reporting unit substantially exceeded its carrying value ("cushion"), which includes $345.7 million of goodwill, by approximately 41 percent.

The increase in the natural gas distribution reporting unit's cushion from the prior year was primarily attributable to the risk adjusted cost of capital decreasing from 6.7 percent in 2023 to 5.9 percent in 2024, which directly correlates with the treasury rates at the date of the test.

The increase in the natural gas distribution reporting unit's cushion from the prior year was primarily driven by improved valuation results under the market approach, reflecting higher industry multiples, as well as an increase in the income approach valuation due to additional rate relief in 2025 compared to 2024.

Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, long-term growth rates, amount and timing of estimated capital expenditures, inflation rates, risk adjusted cost of capital, operational plans, and current and future economic conditions, among others.

4 unchanged sentences

Both values are discounted using a rate which reflects the best estimate of the risk adjusted cost of capital at each reporting unit.

The risk adjusted cost of capital was 5.9 percent, 6.7 percent and 6.4 percent for 2024, 2023 and 2022, respectively for its natural gas distribution reporting unit.

The risk adjusted cost of capital was 5.8 percent, 5.9 percent and 6.7 percent for 2025, 2024, and 2023, respectively.

Under the market approach, the Company estimates fair value using various multiples derived from enterprise value to EBITDA for comparative peer companies.

7 unchanged sentences

Future results of operations may vary due to economic and financial impacts.

The long-term growth rates are developed by management based on industry data, management's knowledge of the industry and management's strategic plans, which was 3.0 percent in 2024 and 2023 and 2.85 percent in 2022.

The long-term growth rates are developed by management based on industry data, management's knowledge of the industry and management's strategic plans, which was 3.0 percent in 2025, 2024, and 2023.

MDU Resources Group, Inc.

Regulatory accounting

9 unchanged sentences

At December 31, 2025 and 2024, regulatory assets in recovery were $437.6 million and $478.5 million, respectively, and regulatory assets not in recovery were $39.2 million and $59.3 million, respectively.

MDU Resources Group, Inc.

Revenue recognition

Revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The recognition of revenue requires the Company to make estimates and assumptions that affect the reported amounts of revenue.

The accuracy of revenues reported on the Consolidated Financial Statements depends on, among other things, management's estimates of total costs to complete projects because the Company used the cost-to-cost measure of progress on construction contracts for revenue recognition.

For the years ended December 31, 2024, 2023 and 2022, the Company's total construction contract revenue, was $2.3 billion, $2.8 billion and $2.6 billion, respectively, which is reflected is discontinued operations due to the separations of Knife River and Everus.

To determine the proper revenue recognition method for contracts, the Company evaluates whether two or more contracts should be combined and accounted for as one single contract and whether the combined or single contract should be accounted for as more than one performance obligation.

This evaluation requires significant judgment and the decision to combine a group of contracts or separate the combined or single contract into multiple performance obligations could change the amount of revenue and profit recorded in a given period.

For most contracts, the customer contracts with the Company to provide a significant service of integrating a complex set of tasks and components into a single project.

Hence, the Company's contracts are generally accounted for as one performance obligation.

The Company recognized construction contract revenue over time using an input method based on the cost-to-cost measure of progress for contracts because it best depicts the transfer of assets to the customer which occurs as the Company incurs costs on the contract.

Under the cost-to-cost measure of progress, the costs incurred are compared with total estimated costs of a performance obligation.

Revenues are recorded proportionately to the costs incurred.

This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs.

Since contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners.

Changes in estimates could have a material effect on the Company's results of operations, financial position and cash flows.

Several factors were evaluated in determining the bid price for contract work.

These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates.

As a project commences, estimates were continually monitored and revised as information became available and actual costs and conditions surrounding the job became known.

If a loss was anticipated on a contract, the loss was immediately recognized.

Contracts are often modified to account for changes in contract specifications and requirements.

The Company considered contract modifications to exist when the modification either created new or changes the existing enforceable rights and obligations.

Generally, contract modifications were for goods or services that are not distinct from the existing contract due to the significant integration of services provided in the context of the contract and were accounted for as if they were part of that existing contract.

The effect of a contract modification on the transaction price and the measure of progress for the performance obligation to which it relates, was recognized as an adjustment to revenue on a cumulative catch-up basis.

The Company's construction contracts generally contained variable consideration including liquidated damages, performance bonuses or incentives, claims, unpriced change orders and penalties or index pricing.

The variable amounts usually arose upon achievement of certain performance metrics or change in project scope.

The Company estimated the amount of revenue to be recognized on variable consideration using one of the two prescribed estimation methods, the expected value method or the most likely amount method, depending on which method best predicted the most likely amount of consideration the Company expected to be entitled to or expected to incur.

Assumptions as to the occurrence of future events and the likelihood and amount of variable consideration were made during the contract performance period.

Estimates of variable consideration and assessment of anticipated performance and all information (historical, current and forecasted) that was reasonably available to management.

The Company only included variable consideration in the estimated transaction price to the extent it was probable that a significant reversal of cumulative revenue recognized would not occur or when the uncertainty associated with the variable consideration was resolved.

Changes in circumstances could have impacted management's estimates made in determining the value of variable consideration recorded.

When determining if the variable consideration was constrained, the Company considered if factors existed that could increase the likelihood of the magnitude of a potential reversal of revenue.

The Company updated its estimate of the transaction price each reporting period and the effect of variable consideration on the transaction price was recognized as an adjustment to revenue on a cumulative catch-up basis.

The Company believes its estimates surrounding the cost-to-cost method are reasonable based on the information that is known when the estimates are made.

The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis.

Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past as new information became available for each job.

Pension and other postretirement benefits

2 unchanged sentences

Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions.

54 MDU Resources Group, Inc.

The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term return on plan assets, actuarially determined mortality data and health care cost trend rates.

19 unchanged sentences

$ (1.2) $ 1.2 $ (.4) $ .4

60 MDU Resources Group, Inc.

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

22 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis