The Company generates, transmits and distributes electricity and provides natural gas distribution, transportation and storage services. Through a strategy focusing on its "CORE," the Company strives to deliver superior value and achieve industry-leading performance as a pure-play regulated energy delivery company, while pursuing organic growth opportunities. The Company's "CORE" strategy prioritizes customers and communities, operational excellence, returns focused initiatives and an employee driven culture. Dividends The Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 88-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend. Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, higher interest rates, changes in tariffs, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business. For more information specific to each of the Company's businesses, see the following discussion in each business segment's Outlook section. For more information on the possible impacts, see Part I, Item 1A. Risk Factors in the 2025 Annual Report. Cautionary Note Regarding Forward-Looking Statements This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Other than statements of historical facts, all statements which address activities, events, or developments that the Company anticipates will or may occur in the future are based on underlying assumptions (many of which are based, in turn, upon further assumptions), including, but not limited to, statements identified by the words "anticipates," "estimates," "expects," "intends," "plans," and "predicts," in each case related to such things as growth estimates, stockholder value creation, the Company's "CORE" strategy, capital expenditures, financial guidance, trends, objectives, goals, dividend payout ratio targets, customer rates, regulatory approvals, sustainability, strategies and other such matters, are forward-looking statements. These forward-looking statements are based on many assumptions and factors, which are detailed in the Company's filings with the SEC. While made in good faith, these forward-looking statements are based largely on the Company's expectations and judgments and are subject to a number of risks and uncertainties, many of which are unforeseeable and beyond the Company's control. For additional discussion regarding risks and uncertainties that may affect forward-looking statements, see Part I, Item 1A. Risk Factors in the 2025 Annual Report and subsequent filings with the SEC. Any changes in such assumptions or factors could produce significantly different results. Undue reliance should not be placed on forward-looking statements, which speak only as of the date they are made. Except as required by applicable law, the Company undertakes no obligation to update the forward-looking statements, whether as a result of new information, future events, or otherwise. 32 Index Consolidated Earnings Overview The following table summarizes the contribution to the consolidated income by each of the Company's business segments. Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions, except per share amounts) Electric $ 14.7 $ 10.4 $ 29.2 $ 25.4 Natural gas distribution (3.9) (7.4) 40.3 37.3 Pipeline 14.4 15.4 29.7 32.6 Other (5.9) (4.3) 1.0 1.3 Income from continuing operations 19.3 14.1 100.2 96.6 Discontinued operations, net of tax 2.0 (.4) 1.9 (.9) Net income $ 21.3 $ 13.7 $ 102.1 $ 95.7 Earnings per share - basic: Income from continuing operations $ .09 $ .07 $ .48 $ .47 Discontinued operations, net of tax .01 — .01 — Earnings per share - basic $ .10 $ .07 $ .49 $ .47 Earnings per share - diluted: Income from continuing operations $ .09 $ .07 $ .48 $ .47 Discontinued operations, net of tax .01 — .01 — Earnings per share - diluted $ .10 $ .07 $ .49 $ .47 Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 The Company's consolidated earnings increased $7.6 million. Drivers of the earnings increase include: •The electric business earnings increase was largely the result of higher retail sales revenue, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm. Interim rates in Montana and new rates in Wyoming, along with higher retail sales volumes across all major customer classes, further drove the increase. The increase was partially offset by higher interest expense associated with debt issuances for recent capital investments, including Badger Wind Farm, as well as higher depreciation expense and operation and maintenance expense, primarily related to Badger Wind Farm. •The natural gas distribution business reported a decreased seasonal loss, primarily driven by new rates in Idaho, Washington, Montana and Wyoming, as well as higher retail sales volumes across all customer classes. These impacts were partially offset by higher interest expense resulting from higher long-term debt balances. •The earnings decrease at the pipeline business was driven by lower other income and higher depreciation and amortization expense from a growth project placed in service. These impacts were partially offset by continued customer demand for short-term natural gas transportation contracts and interruptible storage services, as well as contributions from previously constructed growth projects, including a contracted volume increase. •Other experienced an increase in net income primarily due to income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate. Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 The Company's consolidated earnings increased $6.4 million. Drivers of the earnings increase include: •The electric business earnings increase was largely the result of higher retail sales revenue, primarily from recovery mechanisms associated with renewable investments including Badger Wind Farm. Interim rates in Montana and new rates in Wyoming further drove the increase. The increase was partially offset by higher interest expense associated with debt issuances for recent capital investments, including Badger Wind Farm, as well as higher depreciation expense and operation and maintenance expense, primarily related to Badger Wind Farm. •The natural gas distribution business reported an increase in earnings, primarily driven by new rates in Washington, Idaho, Montana and Wyoming. The increase was partially offset by lower retail sales and electric generation transportation volumes due to warmer first quarter weather. Higher interest expense resulting from higher debt balances, lower other income, and higher operation and maintenance expense, primarily attributable to increased payroll-related costs, further offset the increase. 33 Index •The decrease in earnings at the pipeline business was driven by lower other income. The business also incurred higher operation and maintenance expense, primarily attributable to higher payroll-related costs, materials, and consulting and legal costs associated with the business's recently filed rate case. Lower interruptible natural gas storage withdrawals and higher Montana property tax accruals also contributed to the decrease. These impacts were partially offset by continued customer demand for short-term natural gas transportation contracts, as well as contributions from previously constructed growth projects, including a contracted volume increase. •Other experienced an increase in net income primarily due to income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate. A discussion of key financial data from the Company's business segments follows. Business Segment Financial and Operating Data The following sections include key financial and operating data for each of the Company's business segments. Also included are highlights on key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters of the Company's business segments. For information pertinent to various commitments and contingencies, see the Condensed Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Note 14 of the Condensed Notes to Consolidated Financial Statements. Electric and Natural Gas Distribution Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Note 14. Both segments strive to be top performing utilities and provide safe, reliable, competitively priced and environmentally responsible energy services to customers. The segments are focused on cultivating organic growth while managing operating costs and monitoring opportunities for these segments to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation, transmission and distribution, and natural gas systems. The continued efforts to create operational improvements and efficiencies across both segments promotes the Company's business integration strategy. The primary factors that impact the results of these segments are the ability to earn authorized rates of return; weather; climate change laws, regulations and initiatives; competitive factors in the energy industry; population growth; and economic conditions in the segments' service areas. The electric and natural gas distribution segments are subject to extensive regulation in the jurisdictions where they conduct operations with respect to costs, timely recovery of investments and permitted returns on investment. The Company is focused on modernizing utility infrastructure to meet the varied energy needs of both its customers and communities while working to deliver safe, reliable, affordable and environmentally responsible energy. The segments continue to invest in facility upgrades to be in compliance with existing and known future regulations. To assist in the reduction of regulatory lag in obtaining revenue increases to align with increased investments, tracking mechanisms have been implemented in certain jurisdictions. The Company also seeks rate adjustments for operating costs and capital investments, as well as reasonable returns on investments not covered by tracking mechanisms. For more information on the Company's tracking mechanisms and recent rate cases, see Note 10 and the 2025 Annual Report. These segments are also subject to extensive regulation related to certain operational and environmental compliance, cybersecurity, permit terms and system integrity. Both segments are faced with the ongoing need to actively evaluate cybersecurity processes and procedures related to its transmission and distribution systems for opportunities to further strengthen its cybersecurity protections. There have been cyber and physical attacks within the energy industry on infrastructure, such as substations, and the Company continues to evaluate the safeguards implemented to protect its electric and natural gas utility systems. Implementation of enhancements and additional requirements to protect the Company's infrastructure is ongoing. To date, many states have enacted and others are considering, mandatory energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends as a means to address economy-wide carbon emission concerns, large data center growth and changing customer conservation patterns. MISO and NERC announced concerns with reliability of the electric grid due to rapid expansion of renewables and retirement of baseload resources such as coal and the uncertainty of adequate energy production during certain periods of time, while load growth has increased faster than expected due to large power users. The Company will continue to monitor the progress of these changes, including the impacts associated with the implementation of MISO's direct loss of load accreditation in 2028, and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures. 34 Index Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather, as well as impacts associated with commercial and industrial slow-downs, including economic recessions, and energy efficiencies. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among residential and commercial customers. Average consumption among both electric and natural gas customers has tended to decline as more efficient lighting, appliances, and furnaces are installed, and as the Company has implemented conservation programs. Natural gas weather normalization and decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins. The Company continues to proactively monitor and work with its manufacturers to reduce the effects of increased pricing and lead times on delivery of certain raw materials and equipment used in electric generation, transmission and distribution system and natural gas pipeline projects. Long lead times are attributable to increased demand for steel products from pipeline companies as they continue pipeline system safety and integrity replacement projects driven by PHMSA regulations, as well as delays in the manufacturing and shipping of electrical equipment and increased demand for electrical equipment due to regulatory activity and grid expansion. The Company has been able to minimize the effects by working closely with suppliers or obtaining additional suppliers, as well as modifying project plans to accommodate extended lead times and increased costs. The Company expects these delays to continue. Inflationary pressures remain volatile and costs for goods and services also remain high. The Company also continues to monitor the impact tariffs will have on its costs. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report. The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to higher costs and long lead times for equipment, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. In October 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. Montana-Dakota and Otter Tail Power Company received approval of a Certificate of Public Convenience and Necessity from the NDPSC in November 2024 on this project. The route permit for the JETx line was approved by the NDPSC in June 2026. Earnings overview - The following information summarizes the performance of the electric segment. Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions) Operating revenues $ 116.1 $ 98.1 $ 237.3 $ 210.5 Operating expenses: Electric fuel and purchased power 38.6 34.9 84.7 78.6 Operation and maintenance 31.2 29.9 60.1 58.5 Depreciation and amortization 20.3 17.4 39.9 34.6 Taxes, other than income 5.4 4.7 10.9 9.5 Total operating expenses 95.5 86.9 195.6 181.2 Operating income 20.6 11.2 41.7 29.3 Other income 1.9 2.7 2.3 3.7 Interest expense 11.2 7.6 23.1 15.5 Income before income taxes 11.3 6.3 20.9 17.5 Income tax benefit (3.4) (4.1) (8.3) (7.9) Net income $ 14.7 $ 10.4 $ 29.2 $ 25.4 35 Index Operating statistics Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Revenues (millions) Retail sales: Residential $ 35.3 $ 28.3 $ 74.4 $ 66.5 Commercial1 48.8 41.2 95.7 86.4 Industrial 11.0 9.1 20.9 17.9 Other 2.0 1.8 4.0 3.5 97.1 80.4 195.0 174.3 Other 19.0 17.7 42.3 36.2 $ 116.1 $ 98.1 $ 237.3 $ 210.5 Volumes (million kWh) Retail sales: Residential 253.4 235.8 585.4 606.5 Commercial1 732.1 672.7 1,474.0 1,396.6 Industrial 128.7 120.0 249.4 236.7 Other 20.1 20.1 39.3 40.3 1,134.3 1,048.6 2,348.1 2,280.1 Average cost of electric fuel and purchased power per kWh $ .026 $ .024 $ .027 $ .025 1Commercial includes the impact from data centers. Cooling degree days (% warmer (colder) than prior year)1 Montana (8.2) % 30.3 % (6.0) % 31.9 % North Dakota 2.6 % 35.7 % 3.6 % 35.7 % South Dakota 8.2 % 52.3 % 12.7 % 52.4 % Wyoming (7.8) % (16.4) % 0.5 % (14.3) % 1Cooling degree days are a measure of the energy demand for cooling. Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Electric earnings increased $4.3 million as a result of: •Revenue increased $18.0 million. ◦Largely due to: ▪Higher renewable tracker revenues of $7.7 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax benefit, as described below. ▪Higher fuel and purchased power costs of $3.7 million recovered in customer rates and offset in expense, as described below. ▪New rates approved in regulatory proceedings of $3.4 million in Montana and Wyoming. ▪Higher retail sales volumes of $1.8 million across all major customer classes. •Electric fuel and purchased power increased $3.7 million, largely the result of higher demand costs and higher volumes. •Operation and maintenance increased $1.3 million. ◦Largely the result of: ▪Higher contract services related to Badger Wind Farm of $1.0 million. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station planned outage-related costs. ▪Higher payroll-related costs of $600,000. ◦Partially offset by absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income as described below, and timing of software expenses. •Depreciation and amortization increased $2.9 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm. •Taxes, other than income increased $700,000, largely as a result of higher property tax, primarily in North Dakota and Montana. •Other income decreased $800,000, largely the result of lower TSA income, as described above, partially offset by higher returns on the Company's nonqualified benefit plan investments. •Interest expense increased $3.6 million, primarily due to higher long-term debt balances. 36 Index •Income tax benefit decreased $700,000, largely due to higher income before income taxes, partially offset by higher production tax credits of $500,000 driven by Badger Wind Farm as discussed above. Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Electric earnings increased $3.8 million as a result of: •Revenue increased $26.8 million. ◦Largely due to: ▪Higher renewable tracker revenues of $14.4 million, largely due to Badger Wind Farm, which was placed in service in December 2025, partially offset by higher production tax credits offset in income tax benefit, as described below. ▪Higher fuel and purchased power costs of $6.1 million recovered in customer rates and offset in expense, as described below. ▪New rates approved in regulatory proceedings of $3.6 million in Montana and Wyoming. ◦Partially offset by lower retail sales volumes of $800,000, driven primarily by lower residential and commercial volumes, largely due to warmer weather in the first quarter of the year. There was an increase in commercial volumes from data centers as further discussed in the Outlook section. •Electric fuel and purchased power increased $6.1 million, largely the result of higher demand costs and higher volumes. •Operation and maintenance increased $1.6 million. ◦Largely the result of: ▪ Higher contract services related to Badger Wind Farm of $2.0 million. Big Stone Station planned outage-related costs were more than offset by absence of prior year Coyote Station and Wygen III generating station outage-related costs. ▪Higher payroll-related costs of $1.4 million. ◦Partially offset by timing of software expenses and absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income as described below. •Depreciation and amortization increased $5.3 million, largely due to increased property, plant and equipment balances, primarily related to Badger Wind Farm. •Taxes, other than income increased $1.4 million, largely as a result of higher property tax, primarily in North Dakota and Montana. •Other income decreased $1.4 million, largely the result of lower TSA income, as described above, and lower AFUDC due to lower average CWIP balances, partially offset by higher returns on the Company's nonqualified benefit plan investments. •Interest expense increased $7.6 million, primarily due to higher long-term debt balances. •Income tax benefit increased $400,000, largely due to higher production tax credits of $1.5 million driven by Badger Wind Farm as discussed above, partially offset by higher income before income taxes. Earnings overview - The following information summarizes the performance of the natural gas distribution segment. Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions) Operating revenues $ 212.6 $ 206.9 $ 675.1 $ 746.2 Operating expenses: Purchased natural gas sold 103.4 105.8 377.2 456.3 Operation and maintenance 60.8 60.5 126.0 124.1 Depreciation and amortization 26.6 26.5 53.0 52.6 Taxes, other than income 16.8 17.0 43.3 47.6 Total operating expenses 207.6 209.8 599.5 680.6 Operating income (loss) 5.0 (2.9) 75.6 65.6 Other income 3.8 5.1 6.1 8.4 Interest expense 15.9 13.8 32.2 28.6 Income (loss) before income taxes (7.1) (11.6) 49.5 45.4 Income tax (benefit) expense (3.2) (4.2) 9.2 8.1 Net income (loss) $ (3.9) $ (7.4) $ 40.3 $ 37.3 37 Index Operating statistics Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Revenues (millions) Retail sales: Residential $ 111.1 $ 106.1 $ 370.6 $ 397.7 Commercial 63.5 63.4 213.7 253.0 Industrial 8.7 9.4 22.1 25.1 183.3 178.9 606.4 675.8 Transportation and other 29.3 28.0 68.7 70.4 $ 212.6 $ 206.9 $ 675.1 $ 746.2 Volumes (MMdk) Retail sales: Residential 9.1 8.5 35.6 40.3 Commercial 7.4 7.0 26.0 28.9 Industrial 1.1 1.0 2.6 2.7 17.6 16.5 64.2 71.9 Transportation sales: Commercial .3 .3 .9 1.1 Industrial 32.4 38.1 71.3 86.5 32.7 38.4 72.2 87.6 Total throughput 50.3 54.9 136.4 159.5 Average cost of natural gas per dk $ 5.88 $ 6.42 $ 5.88 $ 6.35 Heating degree days (% colder (warmer) than prior year)1 Idaho 7.9 % (21.7) % (15.3) % (0.9) % Minnesota 14.0 % 21.4 % (6.2) % 16.8 % Montana 8.5 % (2.6) % (23.9) % 6.4 % North Dakota2 15.7 % 14.1 % (8.6) % 12.6 % Oregon2 3.0 % (12.4) % (7.6) % (1.4) % South Dakota2 11.5 % 5.2 % (21.4) % 9.7 % Washington2 (10.5) % (22.7) % (12.6) % (3.3) % Wyoming 4.0 % 12.9 % (22.9) % 10.5 % 1Heating Degree days are a measure of the daily temperature demand for energy heating.2Weather normalization or decoupling mechanisms are in place that minimize the weather impact. Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Natural gas distribution reported a decreased seasonal loss of $3.5 million as a result of: •Revenue increased $5.7 million. ◦Largely due to: ▪New rates approved in regulatory proceedings of $7.7 million, primarily in Idaho, Washington, Montana and Wyoming. ▪Higher Montana property tax tracker of $700,000 that was offset in expense, as described below. ▪A 6.7 percent or $500,000 increase in retail sales volumes to all customer classes, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions. ◦Partially offset by: ▪Lower purchased natural gas sold of $2.4 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below. ▪Transportation volumes decreased 14.8 percent or $500,000 primarily the result of lower electric generation volumes. ▪Lower revenue-based taxes of $400,000, recovered in rates and offset in expense, as described below. •Purchased natural gas sold decreased $2.4 million, largely due to lower commodity costs of $9.6 million, partially offset by higher volumes of natural gas purchased of $7.0 million, and net environmental compliance costs of $200,000. •Operation and maintenance increased $300,000. ◦Largely the result of higher payroll-related costs of $2.2 million. ◦Partially offset by absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income, as described below, and timing of software expenses. 38 Index •Depreciation and amortization increased $100,000, of which $1.1 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented in Washington, Oregon, Wyoming and Montana of $1.0 million. •Taxes, other than income decreased $200,000, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, including Montana, which is recovered in rates, as discussed above. •Other income decreased $1.3 million, largely the result of lower TSA income as described above, partially offset by higher returns on the Company's nonqualified benefit plan investments. •Interest expense increased $2.1 million, primarily due to higher long-term debt balances. •Income tax benefit decreased $1.0 million, primarily the result of lower seasonal loss before income taxes. Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Natural gas distribution earnings increased $3.0 million as a result of: •Revenue decreased $71.1 million. ◦Largely due to: ▪Lower purchased natural gas sold of $79.1 million, including net environmental compliance costs, recovered in customer rates and offset in expense, as described below. ▪Lower revenue-based taxes of $4.9 million, recovered in rates and offset in expense, as described below. ▪A 10.7 percent or $3.8 million decrease in retail sales volumes to all customer classes due to warmer weather during the first quarter, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions. ▪Transportation volumes decreased 17.6 percent or $2.2 million primarily the result of lower electric generation volumes largely due to warmer weather during the first quarter. ◦Partially offset by: ▪New rates approved in regulatory proceedings of $17.1 million, primarily in Washington, Idaho, Montana and Wyoming. ▪Higher conservation revenues of $1.3 million that were offset in expense, as described below. •Purchased natural gas sold decreased $79.1 million, largely due to lower volumes of natural gas purchased of $48.6 million, commodity costs of $20.8 million and net environmental compliance costs of $9.7 million. •Operation and maintenance increased $1.9 million. ◦Largely due to: ▪Higher payroll-related costs of $3.4 million. ▪Higher contract services of $1.3 million, including higher rate case expenses. ▪Higher insurance expenses of $1.0 million. ▪Higher conservation-related costs, recovered in rates, as discussed above. ◦Partially offset by: ▪Timing of software expenses and absence of prior year costs associated with services provided to Everus as part of the TSA, offset in other income, as described below. •Depreciation and amortization increased $400,000, of which $2.5 million resulted from increased property, plant and equipment balances related to growth and replacement projects placed in service, partially offset by lower depreciation rates implemented in Washington, Oregon, Montana and Wyoming of $2.1 million. •Taxes, other than income decreased $4.3 million, due to lower revenue-based taxes, as described above, partially offset by higher property taxes, largely in Montana and Washington. •Other income decreased $2.3 million. ◦Primarily due to: ▪Lower TSA revenue of $2.5 million, as described above. ▪Lower net interest income on regulatory deferral balances. ◦Partially offset by: ▪Higher returns on the Company's nonqualified benefit plans of $800,000. •Interest expense increased $3.6 million, primarily due to higher long-term debt balances. •Income tax expense increased $1.1 million, primarily the result of higher income before income taxes. 39 Index Outlook In 2025, the utility business experienced rate base growth of 16.0 percent which includes the purchase of its ownership stake in Badger Wind Farm as discussed below. These segments grew rate base by 8.7 percent annually over the last five years on a compound basis and expect to invest approximately $2.5 billion of capital expenditures over the next five years. Operations are spread across eight states where the Company expects customer growth to be higher than the national average. In 2025, these segments experienced retail customer growth of approximately 1.5 percent, and the Company expects customer growth to continue to average 1 percent to 2 percent per year. This customer growth, along with system upgrades and replacements needed to supply safe and reliable service, will require investments in new and replacement electric and natural gas systems. These segments are exposed to energy price volatility and may be impacted by changes in oil and natural gas exploration and production activity. Rate schedules in the jurisdictions in which the Company's natural gas distribution segment operates contain clauses that permit the Company to file for rate adjustments for changes in the cost of purchased natural gas. Although changes in the price of natural gas are passed through to customers and have minimal impact on the Company's earnings, the natural gas distribution segment's customers may benefit through the Company's utilization of storage and fixed price contracts to help manage price volatility. Recent regulatory developments have the potential to impact the operation and compliance strategy for Coyote Station. In December 2024, the EPA issued a final decision on the NDDEQ's Regional Haze state implementation plan, disapproving the state's conclusion that no additional controls are warranted for Coyote Station during this implementation period. The EPA has not issued a federal implementation plan in place of the state plan. In January 2025, the Coyote Station co-owners filed a petition challenging the plan disapproval for review with the Eighth Circuit. This action is currently being held in abeyance. In February 2025, the co-owners filed a petition for reconsideration with the EPA, which was granted in April 2025. In October 2025, the EPA released an advanced notice of proposed rulemaking seeking input on restructuring the program with the intent to streamline regulatory requirements for states' visibility improvement obligations. The Electric Generation GHG Rule and Mercury and Air Toxics Standards Rule, as discussed below, also have the potential to impact the operation of Coyote Station. The Company is one of four owners of Coyote Station and cannot make a unilateral decision on the plant's future; therefore, the Company could be negatively impacted by decisions of the other owners. The joint owners continue to collaborate in analyzing data and weighing decisions that impact the plant and its employees as well as each company's customers and communities served. In December 2025, the Company completed the acquisition of a 49 percent ownership interest in Badger Wind Farm and placed the asset in service. The completed transaction secures 122.5 MW of the project's total 250 MW generation capacity for the Company and follows the NDPSC's Advance Determination of Prudence and Certificate of Public Convenience and Necessity approvals, confirming the project is a prudent, cost-effective investment for customers. In March 2023, the Company began to provide power for Applied Digital's data center near Ellendale, North Dakota. At full capacity, the data center requires 180 MW of electricity, equivalent to approximately 21 percent of the Company's generation portfolio. Applied Digital's load is purchased from the MISO market and does not impact the power supply available to other customers. The NDPSC approved an electric service agreement to serve an additional 350 MW of data center load with Applied Digital in the Company's service territory. Approximately 60 MW of the incremental data center load is currently online, with the remaining capacity available and awaiting Applied Digital's request to increase service. Load at the second HPC building in Ellendale is expected to begin ramping in the third quarter of 2026. The third HPC building at Ellendale is scheduled to begin ramping in January 2027. In June 2026, the Company announced the signing of a new electric service agreement to serve its newest data center campus near Center, North Dakota. The electric service agreement supports 430 MWs of HPC load and is currently scheduled to come online in the third quarter of 2027, pending various approvals, including NDPSC approval of the electric service agreement. In August 2024, the Company filed a request with the SDPUC seeking approval on an electric service agreement to provide up to 50 MW of electricity to a data center near Leola, South Dakota. Construction of the data center and approval of the electric service agreement which had been pending development of new local siting requirements for data center loads by McPherson County in South Dakota, were effective August 5, 2025. Approval of the electric service agreement with the SDPUC is still pending along with an updated conditional use permit for the data center siting with McPherson County. The Company's approach to serving data center customers, is grounded in protecting existing customers and ensuring that growth creates values for the communities the Company serves. Data center customers are responsible for paying the costs associated with connecting to and being served by the electric system, including infrastructure and energy-related expenses. Through careful planning, regulatory oversight and cost-allocation mechanisms, the Company works to ensure that existing customers are not subsidizing the costs of serving these new customers. At the same time, the additional revenue generated from serving data center customers can help support the electric system and contribute to reducing certain fixed costs by allocating them across a broader customer base. The Company believes this current approach creates benefits for all customers. 40 Index Legislation and rulemaking The Company monitors legislation and rulemaking that may impact its segments. Below are some of the specific actions the Company is monitoring. •In May 2024, the EPA published four final rules, affecting power sector GHG standards, mercury controls, effluent limits and coal ash management. In March 2025, the EPA announced reconsideration of the Electric Generation and GHG Rule, Mercury and Air Toxics Standards Rule, and Effluent Limitations Guidelines Rule. Depending on final outcomes, compliance costs, and regulatory recovery of compliance costs from customers, these rules could have a material adverse effect on the Company's results of operations and cash flows. ◦In June 2025, the EPA proposed repealing and replacing the May 2024 Electric Generation GHG Rule, with options to (a) exclude the power sector from GHG regulations or (b) remove carbon capture and sequestration requirements while retaining efficiency based standards for natural gas fired combustion units. A final rule is expected in 2026. The Company continues to monitor this rulemaking. ◦In February 2026, the EPA repealed the 2024 Mercury and Air Toxics Standard Rule and restored the 2012 Mercury and Air Toxics Standard Rule, under which the Company’s coal plants maintain compliance. The repeal of the 2024 Mercury and Air Toxics Standard Rule is in litigation. ◦The Company determined that the Effluent Limitations Guidelines Rule and related amendments do not have a material impact on the Company. ◦In April 2026, the EPA proposed amendments to federal regulations for coal combustion residuals at legacy coal ash sites. Comments were due in June 2026. •In February 2026, the EPA rescinded the 2009 Endangerment Finding and related motor vehicle GHG standards under the Clean Air Act. This action does not directly address or repeal GHG regulations for power plants and other non-motor vehicle sources. The rescinded rules are in litigation. •In July 2024, the ODEQ published its proposed rules to create a new CPP. The OEQC adopted the rules in November 2024. In April 2026, Cascade joined with 28 other companies, organizations and individuals in filing a lawsuit in the Oregon Court of Appeals challenging the OEQC's statutory authority to adopt the CPP and asking the court to invalidate the CPP. In May 2026, the Oregon Court of Appeals granted a motion to expedite litigation challenging the CPP. The Company will continue to strive to satisfy all requirements set by the CPP while this litigation is underway. The Company intends to meet its obligations first through no-cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and acquiring environmental attributes from low-carbon fuel projects such as RNG. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow. •In Washington, the Climate Commitment Act was adopted by the Washington Legislature in 2021 and became effective in 2023. The Climate Commitment Act establishes a cap-and-invest program designed to reduce GHG emissions over time, while using auctioned allowances to fund state energy and environmental policy goals. The Company intends to meet its compliance obligations through a combination of energy efficiency measures, no-cost allowances, purchased allowances, and carbon offsets. Compliance costs for these regulations are being recovered through customer rates. Due to the timing of regulatory recovery, the purchase of allowances could impact the Company's operating cash flow. •The Washington SBCC in 2023 adopted residential and commercial building code amendments that will significantly limit the use of natural gas for space and water heating in new and retrofitted commercial and residential buildings. In May 2024, the Company filed a joint complaint seeking declaratory and injunctive relief under federal law against the Washington SBCC's adoption of the amended Washington State Energy Code. This complaint was dismissed by the federal district court. Petitioners have appealed this decision to the Ninth Circuit. The Company's opening brief was filed in July 2025. Oral argument before a three-judge panel of the Ninth Circuit was held in February 2026. Initiative Measure No. 2066, which was approved by voters, does not allow the Washington State Energy Code to "in any way prohibit, penalize, or discourage the use of gas for any form of heating, or for uses related to any appliance or equipment, in any building." In May 2025, the King County Superior Court filed an order ruling Initiative Measure No. 2066 unconstitutional. Following the ruling, the Building Industry Association of Washington filed a notice of appeal with the King County Superior Court. The King County Superior Court’s order invalidating Initiative Measure No. 2066 is now pending review by the Washington State Supreme Court. The Court heard oral arguments in the case in January 2026. •In June 2026, the Bend, Oregon City Council passed a Climate Pollution Fee to discourage the use of natural gas in new residential construction. The ordinance is set to take effect in April 2027 and fees apply to certain natural gas appliances in new single-family homes, duplexes, townhomes and accessory dwelling units. It does not apply to manufactured homes, triplexes or larger housing developments, existing buildings, renovations, replacements or commercial construction. 41 Index Pipeline Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and energy-related services, including cathodic protection, as discussed in Note 14. The segment focuses on utilizing its extensive expertise in the design, construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of existing operations, organic growth and investments in energy-related assets within or in close proximity to its current operating areas. The segment focuses on the continual safety and reliability of its systems, which entails building, operating and maintaining safe natural gas pipelines and facilities. The segment continues to evaluate growth opportunities including the expansion of natural gas facilities; incremental pipeline projects; and expansion of energy-related services leveraging on its core competencies. In support of this strategy, the Minot Expansion Project was placed in service in November 2025 and increased system capacity by 7 MMcf of natural gas per day. The segment is exposed to natural gas and oil price volatility including fluctuations in basis differentials. Legislative and regulatory initiatives on increased pipeline safety regulations and environmental matters such as the reduction of methane emissions could also impact the price and demand for natural gas. The pipeline segment is subject to extensive regulation related to certain operational and environmental compliance, cybersecurity, permit terms and system integrity. The Company continues to actively evaluate cybersecurity processes and procedures, including changes in the industry's cybersecurity regulations, for opportunities to further strengthen its cybersecurity protections. Implementation of enhancements and additional requirements is ongoing. The segment reviews and secures existing permits and easements, as well as new permits and easements as necessary, to meet current demand and future growth opportunities on an ongoing basis. Tariff increases on raw materials could negatively affect the Company's construction projects and maintenance work. The Company continues to monitor the impact tariffs will have on its costs. The Company continues to actively manage the national supply chain challenges by working with its manufacturers and suppliers to help mitigate some of these risks on its business. The segment regularly experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work which could delay maintenance work and construction projects potentially causing lost revenues and/or increased costs. The Company is partially mitigating these challenges by planning for extended lead times further in advance. The Company expects these delays to continue. Inflationary pressures remain volatile, and costs for raw material and contract services also remain high. For additional discussion regarding risks and uncertainties, see Part I, Item 1A. Risk Factors in the 2025 Annual Report. The segment focuses on the recruitment and retention of a skilled workforce to remain competitive and provide services to its customers. The industry in which it operates relies on a skilled workforce to construct energy infrastructure and operate existing infrastructure in a safe manner. A shortage of skilled personnel can create a competitive labor market which could increase costs incurred by the segment. Competition from other pipeline companies can also have a negative impact on the segment. Earnings overview - The following information summarizes the performance of the pipeline segment. Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions) Operating revenues $ 56.7 $ 56.3 $ 113.8 $ 113.0 Operating expenses: Operation and maintenance 22.4 22.4 43.2 41.7 Depreciation and amortization 8.3 7.9 16.5 15.9 Taxes, other than income 3.7 3.6 7.5 6.9 Total operating expenses 34.4 33.9 67.2 64.5 Operating income 22.3 22.4 46.6 48.5 Other income .3 1.7 — 2.1 Interest expense 4.2 4.3 8.2 8.5 Income before income taxes 18.4 19.8 38.4 42.1 Income tax expense 4.0 4.4 8.7 9.5 Net income $ 14.4 $ 15.4 $ 29.7 $ 32.6 42 Index Operating statistics Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Transportation volumes (MMdk) 150.4 151.4 293.6 294.9 Customer natural gas storage balance (MMdk): Beginning of period 27.3 22.1 37.6 44.1 Net injection (withdrawal) 14.2 12.5 3.9 (9.5) End of period 41.5 34.6 41.5 34.6 Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025 Pipeline earnings decreased $1.0 million as a result of: •Revenues increased $400,000 as a result of: ◦Increased demand revenue, largely due to: ▪Increased usage of short-term natural gas transportation contracts of $1.0 million. ▪Growth projects placed in service of $400,000. ◦Higher storage-related revenue of $400,000. ◦Partially offset by: ▪Lower interruptible transportation volumes of $700,000. ▪Lower non-regulated project revenue of $600,000, partially offset in operation and maintenance expense, as described below. •Operation and maintenance was comparable to the same period last year. ◦Primarily from: ▪Higher payroll-related costs of $700,000. ▪Higher consulting and legal costs associated with the Company's recent rate case filing. ▪Partially offset by lower non-regulated project costs of $600,000, associated with decreased non-regulated project revenue, as previously discussed. ◦Also reflected is lower costs associated with services provided to Everus as part of the TSA, offset in other income, as described below. •Depreciation and amortization increased $400,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed. •Taxes, other than income was comparable to the same period in the prior year. •Other income decreased $1.4 million. ◦Largely due to: ▪Project development costs incurred in 2026 that were not eligible for capitalization of $800,000. ▪Lower TSA income of $800,000, as described above. ▪Partially offset by higher investment returns on the Company's non-qualified benefit plans of $300,000. •Interest expense decreased $100,000, primarily from lower debt fees and higher AFUDC, largely offset by higher debt balances. •Income tax expense decreased $400,000, largely due to lower income before income taxes. Six Months Ended June 30, 2026, Compared to Six Months Ended June 30, 2025 Pipeline earnings decreased $2.9 million as a result of: •Revenues increased $800,000 as a result of: ◦Increased demand revenue, largely due to: ▪Increased usage of short-term natural gas transportation contracts of $1.4 million. ▪Growth projects placed in service of $800,000. ◦Higher non-regulated project revenue of $700,000, partially offset in operation and maintenance expense, as described below. ◦Partially offset by: ▪Lower interruptible transportation volumes of $1.2 million. ▪Lower storage-related revenue of $800,000. •Operation and maintenance increased $1.5 million. ◦Primarily from: ▪Higher payroll-related costs of $1.0 million. ▪Higher materials costs of $800,000. ▪Higher consulting and legal costs associated with the Company's recent rate case filing. 43 Index ▪Higher non-regulated project costs of $400,000, associated with increased non-regulated project revenue, as previously discussed. ◦Also reflected is lower costs associated with services provided to Everus as part of the TSA, offset in other income, as described below. •Depreciation and amortization increased $600,000 driven largely by higher property, plant and equipment balances related to growth projects placed in service, as previously discussed. •Taxes, other than income increased $600,000, largely due to higher property tax accruals in Montana. •Other income decreased $2.1 million: ◦Largely due to: ▪Lower TSA income of $900,000, as described above. ▪Project development costs incurred in 2026 that were not eligible for capitalization of $900,000. •Interest expense decreased $300,000, primarily from higher AFUDC. •Income tax expense decreased $800,000, largely due to lower income before income taxes. Outlook The Company has continued to experience the effect of associated natural gas production in the Bakken, which has provided opportunities for organic growth projects and increased transportation demand. The completion of organic growth projects has contributed to higher volumes of natural gas the Company transports through its system. Bakken natural gas production is currently at or near record levels and the outlook remains positive with continued growth expected due to increasing gas to oil ratios. Increases in national and global natural gas supply have moderated pressure on natural gas prices and price volatility. While the Company believes there will continue to be varying pressures on natural gas production levels and prices, the long-term outlook for natural gas prices continues to provide growth opportunities for industrial supply and demand related projects and seasonal pricing differentials provide opportunities for natural gas storage services. The Company continues to monitor, evaluate and implement additional GHG emissions reduction strategies, including increased monitoring frequency and emission source control technologies to minimize potential risk. GHG emissions regulations continue to evolve due to congressional actions and agency reconsideration. Methane Waste Emissions Charge regulations finalized in 2024 were eliminated by a resolution of disapproval passed by Congress and signed by the President in March 2025. The OBBBA postponed the Waste Emissions Charge provisions in the Clean Air Act to 2034. The EPA has issued several actions since the Administrator's announcement regarding 31 historic actions to advance the President's "Power the Great American Comeback" agenda, which includes extending deadlines for and reconsidering certain oil and gas new source performance standards as well as a proposal to reconsider the Greenhouse Gas Reporting Program. The Company continues to comply with rules as they remain effective, and to monitor and assess these rulemakings and the potential impacts they may have on its business processes, current and future projects, results of operations and disclosures. The Company continues to focus on improving existing operations and on growth opportunities through organic expansion projects in all areas in which it operates, which includes additional projects supporting the needs of local distribution companies, Bakken area producers, electric generation customers and industrial customers in various stages of development, including: •Line Section 32 Expansion project which will provide natural gas transportation service to a new electric generation facility in northwest North Dakota. The project consists of approximately 20 miles of pipe and ancillary facilities and is designed to increase natural gas transportation capacity by 190 MMcf per day, which is supported by a long-term customer agreement. The Company continues to make progress on required surveys and filed its FERC 7(c) application in March 2026. The project is dependent on regulatory approvals and targeted to be in service in late 2028. •Potential Bakken East Pipeline project, which could consist of 350 miles of pipeline construction from western North Dakota to the eastern part of the state, plus additional pipeline laterals. A Binding Open Season concluded in March 2026, with customer requests of approximately 1.4 billion cubic feet per day of natural gas transportation capacity obtained through this process. With recently signed Precedent Agreements, the Company has now executed agreements with all customers that submitted binding open season interest totaling nearly 1.2 billion cubic feet per day of firm natural gas transportation capacity, with a negotiated option in place that may increase contracted volumes to nearly all of the original interest from the Binding Open Season. The Company continues to design the project for 1.4 billion cubic feet per day of transportation capacity. Overall project design is being finalized based on confirmed customer volumes and delivery locations before a final investment decision is made, which is expected ahead of a FERC Section 7(c) application. This application is now anticipated to be filed in the fourth quarter of 2026. Included in the open season results is a firm capacity commitment from the State of North Dakota of up to $50 million annually for 10 years, reinforcing the strategic importance of the project to the region's energy infrastructure and economic development opportunities. As development progresses, the Company continues to evaluate all financing options to support the projected $2.7 billion to $3.2 billion project. This investment would be incremental to the Company's capital investment plan. The Company continues to advance engineering, environmental review and pre-filing activities for the proposed 44 Index Bakken East Project and incur preliminary development costs associated with those activities, which are included in other noncurrent assets on the Company's Consolidated Balance Sheets. The Company has certain contractual and commercial arrangements in place that are intended to mitigate the Company's financial exposure associated with these investments and will continue to evaluate these amounts and their classification in conjunction with project developments as they occur. Phase One of the proposed project is targeted to be complete in late 2029, with Phase Two targeted to be complete in late 2030. •Potential Minot Industrial Pipeline Project, which could consist of an approximately 90-mile pipeline from Tioga, North Dakota to Minot, North Dakota and ancillary facilities. The Company has signed an agreement to support the early stage development of the project which has been extended through late 2026. The project would provide incremental natural gas transportation capacity for anticipated industrial demand. Other Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions) Operating revenues $ .2 $ .1 $ .4 $ .3 Operating expenses: Operation and maintenance .2 .4 .7 .5 Total operating expenses .2 .4 .7 .5 Operating loss — (.3) (.3) (.2) Other income .6 1.6 1.7 3.0 Interest expense .6 .9 2.0 1.9 Income (loss) before income taxes — .4 (.6) .9 Income tax (benefit) expense 5.9 4.7 (1.6) (.4) Income (loss) from continuing operations (5.9) (4.3) 1.0 1.3 Discontinued operations, net of tax 2.0 (.4) 1.9 (.9) Net income (loss) $ (3.9) $ (4.7) $ 2.9 $ .4 Three and Six Months Ended June 30, 2026, Compared to Three and Six Months Ended June 30, 2025 For both the quarter and year-to-date periods, Other reported increased earnings compared to the same periods in 2025. The increases were primarily due to income from discontinued operations associated with a $1.5 million tax benefit related to an election to change the tax method for certain strategic initiative costs. Other also reflects income tax adjustments related to the Company's annualized estimated tax rate. Other includes the activities of the captive insurer which insures various types of risks of the Company's subsidiaries. Also included in Other is general and administrative costs and interest expense previously allocated to the Company's former businesses that did not meet the criteria for discontinued operations. Discontinued operations includes certain costs associated with legacy business activities. Intersegment Transactions Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of intersegment transactions. The amounts related to these items were as follows: Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 (In millions) Intersegment transactions: Operating revenues $ 10.4 $ 10.2 $ 45.4 $ 44.0 Purchased natural gas sold $ 9.9 $ 9.8 $ 44.3 $ 43.1 Operation and maintenance $ .5 $ .4 $ 1.1 $ .9 Other income $ .4 $ 1.2 $ 1.3 $ 2.3 Interest expense $ .4 $ 1.2 $ 1.3 $ 2.3 For more information on intersegment eliminations, see Note 14. 45 Index Liquidity and Capital Commitments At June 30, 2026, the Company had cash, cash equivalents and restricted cash of $46.3 million and available borrowing capacity of $433.7 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year and its other operating and capital requirements from various sources, including internally generated funds; credit facilities and commercial paper of the Company and its subsidiaries, as described in Capital resources; and issuance of debt securities and equity securities using the Company's FSA and ATM program, as needed. Cash flows Six Months Ended June 30, 2026 2025 (In millions) Net cash provided by (used in): Operating activities $ 265.3 $ 334.9 Investing activities (196.1) (174.4) Financing activities (51.1) (168.6) Increase (decrease) in cash, cash equivalents and restricted cash 18.1 (8.1) Cash, cash equivalents and restricted cash -- beginning of year 28.2 66.9 Cash, cash equivalents and restricted cash -- end of period $ 46.3 $ 58.8 Operating activities Six Months Ended June 30, 2026 2025 Variance (In millions) Components of net cash provided by operating activities: Net income $ 102.1 $ 95.7 $ 6.4 Loss from discontinued operations, net of tax 1.9 (0.9) 2.8 Income from continuing operations 100.2 96.6 3.6 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 109.4 103.1 6.3 Deferred income taxes 11.6 (19.0) 30.6 Other adjustments 4.5 4.0 .5 Changes in current assets and liabilities, net of acquisitions: Receivables 103.8 129.5 (25.7) Inventories 19.3 25.0 (5.7) Other current assets (23.0) 86.7 (109.7) Accounts payable (36.4) (47.6) 11.2 Other current liabilities (7.6) (28.4) 20.8 Pension & postretirement benefit plan contributions (1.0) (2.5) 1.5 Other noncurrent changes (16.8) (11.8) (5.0) Net cash provided by continuing operations 264.0 335.6 (71.6) Net cash provided by (used in) discontinued operations 1.3 (.7) 2.0 Net cash provided by operating activities $ 265.3 $ 334.9 $ (69.6) The changes in cash flows from operating activities generally follow the results of operations, as discussed in Business Segment Financial and Operating Data, and are affected by changes in working capital. •Net cash provided by continuing operations was $71.6 million lower, primarily attributable to: ◦Other current assets $(109.7) million: due to lower collections of purchased gas costs of $43.0 million, carbon compliance costs of $31.7 million, decoupling balances of $8.2 million, all at the natural gas distribution business; as well as lower fuel cost collections at the electric business of $7.1 million. ◦Receivables $(25.7) million: due to lower collection of accounts receivable due to warmer than normal weather in December 2025. ◦Other noncurrent changes $(5.0) million: due to increased preliminary project costs incurred in 2026 versus 2025. ◦Partially offset by: ▪Deferred income taxes $30.6 million: which resulted from higher plant related deferrals of $14.4 million, purchased gas cost adjustments of $9.8 million, and environmental compliance deductions of $2.2 million. 46 Index ▪Other current liabilities $20.8 million: due to higher environmental compliance obligations due to customers of $26.2 million, a large load customer deposit of $12.0 million, and higher electric fuel balances owed to customers of $9.5 million; partially offset by lower income taxes paid of $30.6 million. Investing activities Six Months Ended June 30, 2026 2025 Variance (In millions) Components of net cash used in investing activities: Capital expenditures $ (193.5) $ (174.0) $ (19.5) Cost of removal, net of salvage value (3.9) (2.5) (1.4) Purchase of investment securities (2.7) (2.9) .2 Proceeds from investment securities 4.0 5.0 (1.0) Net cash used in investing activities $ (196.1) $ (174.4) $ (21.7) •Net cash used in investing activities was $21.7 million higher, primarily attributable to: ◦Capital expenditures $(19.5) million: due to higher natural gas distribution expenditures of $27.9 million, partially offset by lower electric wind project expenditures of $12.2 million. Financing activities Six Months Ended June 30, 2026 2025 Variance (In millions) Components of net cash used in financing activities: Issuance of long-term debt $ 134.5 $ — $ 134.5 Repayment of long-term debt (234.0) (111.0) (123.0) Debt issuance costs (.6) — (.6) Issuance of common stock, net 110.8 — 110.8 Dividends paid (57.3) (53.1) (4.2) Tax withholding on stock-based compensation (4.5) (4.5) — Net cash used in financing activities $ (51.1) $ (168.6) $ 117.5 •Net cash used in financing activities was $117.5 million lower, primarily attributable to: ◦Issuance of long-term debt $134.5 million: of which $100.0 million of senior notes were issued under a NPA and $34.5 million was issued under the revolving credit agreement facilities. ◦Issuance of common stock $110.8 million: of which $81.2 million was partial settlement under the Company's FSA and $29.6 million was net issuances under the Company's ATM program. ◦Partially offset by: ▪Repayment of long-term debt $(123.0) million: due to increased repayments primarily at Montana-Dakota. ▪Dividends paid $(4.2) million: higher dividends paid due to an increase in the dividends declared per common share and an increase in the number of average common shares outstanding. Capital expenditures Capital expenditures for the first six months of 2026 and 2025 were $193.8 million and $179.4 million, respectively. Capital expenditures at the Company's business segments are estimated to be approximately $529.2 million for 2026, which is a slight reduction to what was previously reported in the 2025 Annual Report due to the timing of JETx capital expenditures. Capital expenditure estimates have been updated to accommodate project timeline and scope changes made thus far in 2026. Planned utility investments in the Company's estimated capital expenditures for 2026 through 2028 include system upgrades, substation improvements and generation projects, construction of JETx, system replacements, expansion and modernization projects to meet demand from a growing customer base, including new service extensions and capacity expansion to accommodate economic and population growth across the Company's eight-state territory. The pipeline business will continue to evaluate customer-driven projects, including expansion projects, to serve power generation and industrial demand in the region. In addition, the pipeline will focus on system maintenance and expanding capacity where market conditions support additional investment. Investment in the potential Bakken East Pipeline project would be incremental to the outlined capital program. A number of projects are included in the planned investments as the Company continues to invest in safe, reliable and environmentally-responsible energy delivery infrastructure across its regulated businesses. For more information on the Company's growth projects, see Business Segment Financial and Operating Data. 47 Index The Company continues to evaluate potential future acquisitions and other growth opportunities that would be incremental to the outlined capital program; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimate previously discussed. The Company continuously monitors its capital expenditures for project delays and changes in economic viability and adjusts as necessary. It is anticipated that all funds required for capital expenditures for the years 2026 through 2028 will be funded by various sources, including equity issuance, debt financing and internally generated funds. Capital resources The Company requires significant cash to support and grow its businesses. The primary sources of cash other than cash generated from operating activities are cash from revolving credit facilities, the issuance of long-term debt and the sale of equity securities. Debt resources Certain debt instruments of the Company and its subsidiaries contain restrictive and financial covenants and cross-default provisions. In order to borrow under the respective debt instruments, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions. The Company and its subsidiaries were in compliance with applicable covenants at June 30, 2026. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. As of June 30, 2026, the Company had investment grade credit ratings at all entities issuing debt. For more information on the Company's debt instruments, covenants, certain other conditions and cross-default provisions, see Note 13 and Part II, Item 6 in this document and Part II, Item 8 in the 2025 Annual Report. Equity offerings In August 2025, the Company entered into an EDA pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $400.0 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs. Since the establishment of the ATM offering program, the Company did not enter into any FSAs related to the EDA. As of June 30, 2026, the Company had capacity to issue up to an aggregate gross sales price of $370.0 million in shares of common stock under the ATM offering program. On December 5, 2025, the Company completed a follow-on public offering of 10.2 million shares of the Company's common stock at a public offering price of $19.70 per share. In addition, on December 23, 2025, the underwriters exercised their option to purchase 1.5 million additional shares of the Company's common stock. Pursuant to the FSAs entered into in connection with the offering, the Company has the discretion to settle the FSAs on one or more settlement dates prior to December 6, 2027, subject to certain price adjustments as set forth in the FSAs as well as adjustments for transaction and other associated fees. The FSAs will be physically settled with shares of common stock issued by the Company, unless the Company elects to settle the FSAs in net cash or net shares, subject to certain conditions. If the Company elects to physically settle the FSAs, the Company will physically issue shares of common stock to the banking counterparties at the then-applicable forward sale price and receive proceeds at that time. In March 2026, the Company partially settled the FSAs with physical delivery of 4.3 million shares of common stock to the counterparties in exchange for cash of $81.3 million. At June 30, 2026, the Company could have settled all of its outstanding FSAs with physical delivery of 7.4 million shares of common stock to the banking counterparties in exchange for cash of approximately $139.6 million. If the FSAs had been net cash or net share settled at June 30, 2026, the Company estimates that the counterparties, in aggregate, would have been entitled to a net settlement of $16.8 million or 792,557 shares, respectively. Actual cash proceeds, if any, for settlement of FSAs will depend on the method and timing the Company elects for settlement. Prior to settlement, the potentially issuable shares pursuant to the FSAs were and will be reflected in the Company's diluted earnings per share calculation using the treasury stock method. For more detailed information about the Company's equity transactions, see Note 8. Material cash requirements There were no material changes in the Company's remaining contractual obligations related to estimated interest payments, asset retirement obligations and uncertain tax positions for 2026 from those reported in the 2025 Annual Report. For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Part II, Item 7 in the 2025 Annual Report. Material short-term cash requirements of the Company include repayment of outstanding borrowings and interest payments on those agreements, payments on operating lease agreements, payment of obligations on purchase commitments and asset retirement obligations. Material long-term cash requirements of the Company include repayment of outstanding borrowings and interest payments on those agreements, payments on operating lease agreements, payment of obligations on purchase commitments and asset retirement obligations. 48 Index Defined benefit pension plans The Company has noncontributory qualified defined benefit pension plans for certain employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans, as such costs of providing these benefits bear the risk of changes as they are dependent upon assumptions of future conditions. There were no material changes to the Company's noncontributory qualified defined benefit pension plans from those reported in the 2025 Annual Report other than the Company now expects to contribute approximately $3.7 million to its pension plans in 2026. For more information, see Note 15 and Part II, Item 7 in the 2025 Annual Report. New Accounting Standards For information regarding new accounting standards, see Note 2, which is incorporated by reference. Critical Accounting Estimates The Company's critical accounting estimates include impairment testing of goodwill; regulatory assets expected to be recovered in rates charged to customers; actuarially determined pension and other postretirement benefit costs; and income taxes. There were no material changes in the Company's critical accounting estimates from those reported in the 2025 Annual Report. For more information on critical accounting estimates, see Part II, Item 7 in the 2025 Annual Report.