MDU RESOURCES GROUP INC

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Dividends The Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 87-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.

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Dividends The Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 88-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend.

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Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, higher interest rates, changes in tariffs, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business. The Company has observed supply chain improvements in lead times for certain commodities. The Company has experienced impacts related to the changes in tariffs and continues to navigate the current environment and monitor the future for impacts that could occur. For more information specific to each of the Company's businesses, see the following discussion in each business segment's Outlook section. For more information on the possible impacts, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

Current wording

Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, higher interest rates, changes in tariffs, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business. For more information specific to each of the Company's businesses, see the following discussion in each business segment's Outlook section. For more information on the possible impacts, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

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Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 The Company's consolidated earnings decreased $1.2 million. Drivers of the earnings decrease include:

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Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 The Company's consolidated earnings increased $7.6 million. Drivers of the earnings increase include:

Previous wording

•Other experienced an increase in net income primarily due to income tax adjustments related to the Company's annualized estimated tax rate. Partially offsetting the increase was higher operation and maintenance expense.

Current wording

•Other experienced an increase in net income primarily due to income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate.

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•The electric business earnings decrease was largely the result of higher interest expense associated with debt issuances for recent capital investments including Badger Wind Farm. Lower retail sales volumes due to warmer weather and higher depreciation expense, primarily Badger Wind Farm, further drove the decrease. Higher retail revenues, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm, largely offset the decrease.

Current wording

•The electric business earnings increase was largely the result of higher retail sales revenue, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm. Interim rates in Montana and new rates in Wyoming further drove the increase. The increase was partially offset by higher interest expense associated with debt issuances for recent capital investments, including Badger Wind Farm, as well as higher depreciation expense and operation and maintenance expense, primarily related to Badger Wind Farm.

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•The earnings decrease at the pipeline business was driven by lower interruptible natural gas storage withdrawals. Higher operation and maintenance expense primarily attributable to higher materials and payroll-related costs also contributed, as well as higher Montana property tax accruals. The decrease was partially offset by continued strong customer demand for short-term natural gas transportation contracts, as well as impacts from a growth project placed in service in 2025 and a contracted volume increase associated with a previously constructed growth project.

Current wording

•The decrease in earnings at the pipeline business was driven by lower other income. The business also incurred higher operation and maintenance expense, primarily attributable to higher payroll-related costs, materials, and consulting and legal costs associated with the business's recently filed rate case. Lower interruptible natural gas storage withdrawals and higher Montana property tax accruals also contributed to the decrease. These impacts were partially offset by continued customer demand for short-term natural gas transportation contracts, as well as contributions from previously constructed growth projects, including a contracted volume increase.

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To date, many states have enacted and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns. MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to growth in the data center industry. The Company will continue to monitor the progress of these changes, including the impacts associated with the implementation of MISO's direct loss of load accreditation in 2028, and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures.

Current wording

To date, many states have enacted and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns. MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to large power users. The Company will continue to monitor the progress of these changes, including the impacts associated with the implementation of MISO's direct loss of load accreditation in 2028, and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures.

Previous wording

The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures have moderated but costs for goods and services remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

Current wording

The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures remain volatile and costs for goods and services also remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

Previous wording

The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to higher costs and long lead times for equipment, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project. The route permit for the JETx line was filed with the NDPSC in August 2025. JETx is expected to be placed in service in 2029.

Current wording

The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to higher costs and long lead times for equipment, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project. The route permit for the JETx line was approved by the NDPSC in June 2026.

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Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 Electric earnings decreased $500,000 as a result of:

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Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Electric earnings increased $4.3 million as a result of:

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▪Higher renewable tracker revenues of $6.7 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax benefit, as described below.

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▪Higher renewable tracker revenues of $7.7 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax benefit, as described below.

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▪Higher fuel and purchased power costs of $2.4 million recovered in customer rates and offset in expense, as described below.

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▪Higher fuel and purchased power costs of $3.7 million recovered in customer rates and offset in expense, as described below.

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•Electric fuel and purchased power increased $2.4 million, largely the result of higher demand costs, primarily driven by data centers.

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•Electric fuel and purchased power increased $3.7 million, largely the result of higher demand costs and higher volumes.

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▪Higher materials costs of $600,000.

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▪Higher payroll-related costs of $600,000.

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•Depreciation and amortization increased $2.4 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.

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•Depreciation and amortization increased $2.9 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm.

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◦Partially offset by lower retail sales volumes of $2.6 million, driven primarily by lower residential and commercial volumes, largely due to warmer weather. There was an increase in commercial volumes from data centers as further discussed in the Outlook section.

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◦Partially offset by lower retail sales volumes of $800,000, driven primarily by lower residential and commercial volumes, largely due to warmer weather in the first quarter of the year. There was an increase in commercial volumes from data centers as further discussed in the Outlook section.

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◦Largely the result of $1.4 million higher contract services related to Badger Wind Farm of $900,000 and timing of tree trimming of $400,000. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station and Wygen III generating station outage-related costs.

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▪ Higher contract services related to Badger Wind Farm of $2.0 million. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station and Wygen III generating station outage-related costs.

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◦Partially offset by timing of software expenses.

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◦Partially offset by timing of software expenses and absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income as described below.

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•Other income decreased $600,000, largely the result of lower AFUDC due to lower average CWIP balances.

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•Other income decreased $1.4 million, largely the result of lower TSA income, as described above, and lower AFUDC due to lower average CWIP balances, partially offset by higher returns on the Company's nonqualified benefit plan investments.

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•Income tax benefit increased $1.1 million, largely due to higher production tax credits of $1.0 million driven by Badger Wind Farm as discussed above, and lower income before income taxes.

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•Income tax benefit increased $400,000, largely due to higher production tax credits of $1.5 million driven by Badger Wind Farm as discussed above, partially offset by higher income before income taxes.

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Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 Natural gas distribution earnings decreased $500,000 as a result of:

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Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Natural gas distribution reported a decreased seasonal loss of $3.5 million as a result of:

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▪Lower purchased natural gas sold of $76.7 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.

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▪Lower purchased natural gas sold of $2.4 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below.

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•Depreciation and amortization increased $300,000, of which $1.3 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented in Washington, Oregon, Montana and Wyoming of $1.1 million.

Current wording

•Depreciation and amortization increased $100,000, of which $1.1 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented in Washington, Oregon, Wyoming and Montana of $1.0 million.

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▪Lower revenue-based taxes of $4.5 million, recovered in rates and offset in expense, as described below.

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▪Lower revenue-based taxes of $4.9 million, recovered in rates and offset in expense, as described below.

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▪A 15.9 percent or $4.3 million decrease in retail sales volumes to all customer classes due to warmer weather, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.

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▪A 10.7 percent or $3.8 million decrease in retail sales volumes to all customer classes due to warmer weather during the first quarter, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions.

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▪Transportation volumes decreased 19.7 percent or $1.7 million primarily the result of lower electric generation volumes largely due to warmer weather.

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▪Transportation volumes decreased 17.6 percent or $2.2 million primarily the result of lower electric generation volumes largely due to warmer weather during the first quarter.

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▪Rate relief of $9.4 million, primarily in Washington, Idaho, Montana and Wyoming.

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▪New rates approved in regulatory proceedings of $17.1 million, primarily in Washington, Idaho, Montana and Wyoming.

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▪Higher conservation revenues of $800,000 that were offset in expense, as described below.

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▪Higher conservation revenues of $1.3 million that were offset in expense, as described below.

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•Purchased natural gas sold decreased $76.7 million, largely due to lower volumes of natural gas purchased of $55.6 million, commodity costs of $11.2 million and net environmental compliance costs of $9.9 million.

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•Purchased natural gas sold decreased $79.1 million, largely due to lower volumes of natural gas purchased of $48.6 million, commodity costs of $20.8 million and net environmental compliance costs of $9.7 million.

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•Taxes, other than income decreased $4.1 million, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, largely in Montana and Washington.

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•Taxes, other than income decreased $4.3 million, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, largely in Montana and Washington.

Previous wording

In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, which is the equivalent of about 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact other customers' power supply. An electric service agreement to serve an additional 350 MW data center load with Applied Digital in the Company's service territory was approved by the NDPSC. Approximately 50 MW of the incremental data center load is currently online with an additional 50 MW expected to be fully online by the end of the second quarter of 2026.

Current wording

In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, equivalent to approximately 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact the power supply available to other customers. The NDPSC approved an electric service agreement to serve an additional 350 MW of data center load with Applied Digital in the Company's service territory. Approximately 60 MW of the incremental data center load is currently online, with the remaining capacity available and awaiting Applied Digital's request to increase service. Load at the second HPC building in Ellendale is expected to begin ramping in the third quarter of 2026. The third HPC building at Ellendale is scheduled to begin ramping in January 2027.

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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.

Current wording

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

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◦The Company determined the Effluent Limitations Guidelines Rule and related amendments do not have a material impact on the Company.

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◦The Company determined that the Effluent Limitations Guidelines Rule and related amendments do not have a material impact on the Company.

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◦In April 2026, the EPA proposed amendments to federal regulations for coal combustion residuals at legacy coal ash sites. The Company is evaluating the proposal. Comments are due in June 2026.

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◦In April 2026, the EPA proposed amendments to federal regulations for coal combustion residuals at legacy coal ash sites. Comments were due in June 2026.

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•In July 2024, the ODEQ published its proposed rules to create a new CPP. The OEQC adopted the rules in November 2024. In April 2026, Cascade joined with 28 other companies, organizations and individuals in filing a lawsuit in the Oregon Court of Appeals challenging the OEQC's statutory authority to adopt the CPP and asking the court to invalidate the CPP. The Company will continue to strive to satisfy all requirements set by the CPP while this litigation is underway. The Company intends to meet its obligations first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow.

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•In July 2024, the ODEQ published its proposed rules to create a new CPP. The OEQC adopted the rules in November 2024. In April 2026, Cascade joined with 28 other companies, organizations and individuals in filing a lawsuit in the Oregon Court of Appeals challenging the OEQC's statutory authority to adopt the CPP and asking the court to invalidate the CPP. In May 2026, the Oregon Court of Appeals granted a motion to expedite litigation challenging the CPP. The Company will continue to strive to satisfy all requirements set by the CPP while this litigation is underway. The Company intends to meet its obligations first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow.

Previous wording

Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. The Company continues to monitor the impact tariffs will have on its costs. The Company continues to actively manage the national supply chain challenges by working with its manufacturers and suppliers to help mitigate some of these risks on its business. The segment regularly experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work which could delay maintenance work and construction projects potentially causing lost revenues and/or increased costs. The Company is partially mitigating these challenges by planning for extended lead times further in advance. The Company expects these delays to continue. Inflationary pressures have moderated, but costs for raw material and contract services remain high. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

Current wording

Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. The Company continues to monitor the impact tariffs will have on its costs. The Company continues to actively manage the national supply chain challenges by working with its manufacturers and suppliers to help mitigate some of these risks on its business. The segment regularly experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work which could delay maintenance work and construction projects potentially causing lost revenues and/or increased costs. The Company is partially mitigating these challenges by planning for extended lead times further in advance. The Company expects these delays to continue. Inflationary pressures remain volatile, and costs for raw material and contract services also remain high. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report.

Previous wording

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025 Pipeline earnings decreased $1.9 million as a result of:

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Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Pipeline earnings decreased $1.0 million as a result of:

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▪Increased usage of short-term natural gas transportation contracts of $400,000.

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▪Increased usage of short-term natural gas transportation contracts of $1.0 million.

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•Depreciation and amortization increased $200,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.

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•Depreciation and amortization increased $400,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed.

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•Other income decreased $700,000, largely due to lower investment returns on the Company's non-qualified benefit plans of $300,000.

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▪Partially offset by higher investment returns on the Company's non-qualified benefit plans of $300,000.