MDU RESOURCES GROUP INC 10-K

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The Company provides essential infrastructure and services. The Company and its employees work hard to keep the economy of America moving with the products and services provided, which include powering, heating and connecting homes, factories, offices and stores; and constructing and maintaining electrical and communication wiring and infrastructure. The Company is authorized to conduct business in nearly every state in the United States. The Company’s organic investments are strong drivers of high-quality earnings and continue to be an important part of the Company’s growth. Management believes the Company is well positioned in the industries and markets in which it operates. Chief Executive Officer Transition On January 5, 2024, David L. Goodin, formerly president and chief executive officer of the Company, retired after a 40-year career with the Company. The board of directors unanimously selected Nicole A. Kivisto, formerly president and chief executive officer of the Company's electric and natural gas utility companies, to succeed Mr. Goodin as the Company's president and chief executive officer effective January 6, 2024. Ms. Kivisto became a member of the board of directors at the same time. Strategic Initiatives The Company announced strategic initiatives in 2022 as part of the Company's continuous review of its business. The Company incurred costs in connection with the announced strategic initiatives in 2022 and 2023, as noted in the Business Segment Financial and Operating Data section, and expects to continue to incur these costs until the initiatives are completed. On May 31, 2023, the Company completed the separation of Knife River, formerly the construction materials and contracting segment, which resulted in two independent, publicly traded companies, MDU Resources Group, Inc. and Knife River. The Company's board of directors approved the distribution of approximately 90 percent of the issued and outstanding shares of Knife River to the Company's stockholders. Stockholders of the Company received one share of Knife River common stock for every four shares of the Company's common stock held on May 22, 2023, the record date for the distribution. The Company retained approximately 10 percent or 5.7 million shares of Knife River common stock immediately following the separation, which was disposed of in a tax-free exchange in November 2023. The separation of Knife River was a tax-free spinoff transaction to the Company's stockholders for U.S. federal income tax purposes. On November 2, 2023, the Company announced its intent to pursue a tax-free spinoff of its wholly owned construction services business, MDU Construction Services. The Company's board of directors believes a tax-free spinoff of the construction services business supports the Company's goal of enhancing value for stockholders by becoming a pure-play regulated energy delivery company. See Item 1A - Risk Factors for a description of the risks and uncertainties with the proposed future structure. Based on the Company's anticipated future state as a pure-play regulated energy delivery business, the Company's board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated energy delivery earnings. The Company has an 86-year history of uninterrupted dividend payments to stockholders and remains committed to paying a competitive dividend as the Company transitions to being a pure-play regulated energy delivery company. Market Trends The Company continues to manage the inflationary pressures experienced throughout the United States, including the impact that inflation, rising interest rates, commodity price volatility and supply chain disruptions may have on its business and customers and proactively looks for ways to lessen the impact to its business. Rising interest rates have resulted in and may continue to result in higher borrowing costs on new debt, resulting in impacts to the Company's asset valuations and negatively impacting the purchasing power of its customers. The Company has continued to evaluate its businesses and has increased pricing for its products and services where possible. The ability to raise selling prices to cover higher costs due to inflation are subject to regulatory approval, customer demand, industry competition and the availability of materials, among other things. For more information on possible impacts to the Company's businesses, see the Outlook for each segment below and Item 1A - Risk Factors. MDU Resources Group, Inc. Form 10-K 33 Index Part II Consolidated Earnings Overview The following table summarizes the contribution to the consolidated income by each of the Company's business segments. Years ended December 31, 2023 2022 2021 (In millions, except per share amounts) Electric $ 71.6 $ 57.1 $ 51.9 Natural gas distribution 48.5 45.2 51.6 Pipeline 47.4 36.2 41.1 Construction services 142.4 129.5 112.2 Other 170.5 (17.2) (14.3) Income from continuing operations 480.4 250.8 242.5 Discontinued operations, net of tax (65.7) 116.7 135.6 Net income $ 414.7 $ 367.5 $ 378.1 Earnings per share - basic: Income from continuing operations $ 2.36 $ 1.23 $ 1.20 Discontinued operations, net of tax (.32) .58 .67 Earnings per share - basic $ 2.04 $ 1.81 $ 1.87 Earnings per share - diluted: Income from continuing operations $ 2.36 $ 1.23 $ 1.20 Discontinued operations, net of tax (.33) .58 .67 Earnings per share - diluted $ 2.03 $ 1.81 $ 1.87 2023 compared to 2022 The Company's consolidated earnings increased $47.2 million. The Company experienced increased earnings at each of its continuing businesses. • The electric business experienced higher retail sales due to rate relief in North Dakota and Montana, an electric service agreement to provide power to a data center near Ellendale, North Dakota, and higher transmission interconnect upgrades. Electric earnings were partially offset by lower residential volumes, primarily due to cooler weather in the third quarter of the year. • Natural gas distribution experienced higher retail sales revenue due to rate relief in Idaho and Washington, higher basic service charges, and recovery of short-term debt interest expense in Idaho related to increased gas costs. These increases were largely offset by higher operation and maintenance expense, primarily higher payroll-related costs. The natural gas distribution business also experienced a 6.6 percent decrease in retail sales volumes to all customer classes, largely due to warmer weather, which was partially offset by weather normalization and decoupling mechanisms. • The pipeline's earnings increase was driven by higher transportation volumes, primarily from increased contracted volume commitments from the North Bakken Expansion project and a full year of benefit from this project; as well as organic growth projects placed in service in November 2023 and August 2022. In addition, revenues increased from new transportation and storage rates effective August 1, 2023 and higher storage-related activity. The pipeline also benefited from higher allowance for funds used during construction on organic growth projects, lower property taxes and higher non-regulated project margin. The increase was offset in part by higher operation and maintenance expense primarily attributable to payroll-related costs and contract services. The pipeline business also incurred higher interest expense as a result of higher interest rates and higher debt balances. • The construction services business experienced higher electrical and mechanical gross profit due to progress on hospitality and data center projects in the commercial market and higher industrial margins due to efficiency in labor and material costs. The construction services business also benefited from higher transmission and distribution gross profit. Earnings were partially offset by higher selling, general and administrative expense, largely attributable to increased payroll-related costs associated with operational growth, and higher reserve for uncollectible accounts on certain projects. The construction services business also experienced higher interest expense due to higher working capital needs and interest rates. 34 MDU Resources Group, Inc. Form 10-K Index Part II • Other experienced a realized gain of $186.6 million related to the tax-free exchange of its retained interest in Knife River and higher interest income. Partially offsetting these items were higher interest expense, primarily related to debt issued in connection with the Knife River separation. Other also benefited from improved claims experience at the captive insurer in 2023 compared to 2022. • On May 31, 2023, the Company completed the separation of Knife River, its former construction materials and contracting segment, into a new publicly traded company. As a result of the separation, the historical results of operations for Knife River are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the Company, which are reflected in Other and do not meet the criteria for income (loss) from discontinued operations. Also included in discontinued operations are strategic initiative costs associated with the separation of Knife River. The variance relates to five months of activity for Knife River in 2023 compared to the twelve months in 2022. • The Company's earnings from continuing operations were further impacted by $17.7 million in higher returns on the Company's nonqualified benefit plan investments, as discussed in Note 9, partially offset by higher costs incurred in connection with other strategic initiatives of $7.6 million, after tax. 2022 compared to 2021 The Company's consolidated earnings decreased $10.6 million due to lower earnings at the natural gas distribution and pipeline businesses, as well as in discontinued operations. Partially offsetting were higher earnings at the construction services and electric businesses. • The electric business benefited from interim rate relief in North Dakota, higher net transmission revenues and higher retail sales volumes as a result of colder weather, as well as lower operation and maintenance expenses, largely related to plant closures. • The natural gas distribution business experienced higher operating expenses, including subcontractor costs, as well as higher interest and depreciation expenses, partially offset by increased sales volumes and approved rate recovery in certain jurisdictions. • The pipeline business experienced higher interest expense and lower non-regulated project margins, partially offset by the net benefit of the North Bakken Expansion project. • Increased earnings at the construction services business resulting from higher electrical and mechanical project margins and earnings from the segment's joint ventures, partially offset by higher overall operating expenses related to increased payroll-related costs and expected credit losses. • As previously discussed, the historical results of Knife River are shown in discontinued operations, except for allocated general corporate costs of the Company. The decrease in earnings in 2022 was a result of Knife River being negatively impacted by ongoing inflationary pressures, including energy and other operating costs. In addition, costs incurred in 2022 associated with the separation of Knife River had a negative impact on earnings. • The Company's earnings from continuing operations were further impacted by $17.0 million in lower returns on the Company's nonqualified benefit plan investments, as discussed in Note 9, and the costs incurred in 2022 in connection with other strategic initiatives, which do not meet the criteria for income (loss) from discontinued operations of $3.7 million, after tax. A discussion of key financial data from the Company's business segments follows. Business Segment Financial and Operating Data Following are key financial and operating data for each of the Company's business segments. Also included are highlights on key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters of the Company's business segments. Many of these highlighted points are "forward-looking statements." For more information, see Part I - Forward-Looking Statements. There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Item 1A - Risk Factors. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections. For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Item 8 - Note 18. MDU Resources Group, Inc. Form 10-K 35 Index Part II Electric and Natural Gas Distribution Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Items 1 and 2 - Business Properties. Both segments strive to be top performing utility companies measured by integrity, employee safety and satisfaction, customer service and stockholder return. The segments provide safe, reliable, competitively priced and environmentally responsible energy service to customers while focusing on growth and expansion opportunities within and beyond its existing territories. The Company is focused on cultivating organic growth while managing operating costs and monitoring opportunities for these segments to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation, transmission and distribution, and natural gas systems, and through selected acquisitions of companies and properties with similar operating and growth objectives at prices that will provide stable cash flows and an opportunity to earn a competitive return on investment. 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 ensuring the delivery of 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 Items 1 and 2 - Business Properties and Item 8 - Note 21. 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. Within the past year, 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 clean energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. The current presidential administration has made climate change a focus, as further discussed in the Outlook section. Over the long-term, the Company expects overall electric demand to be positively impacted by increased electrification trends, including electric vehicle adoption, as a means to address economy-wide carbon emission concerns and changing customer conservation patterns. Recently, MISO and NERC announced concerns with reliability of the electric grid due to capacity shortages, which has resulted from rapid expansion of renewables and rapid reduction of baseload resources such as coal, while load growth has increased faster than expected. MISO received FERC approval of a seasonal resource adequacy construct, or accreditation process, versus the previous annual summer peak capacity requirement process. These changes have not had a significant impact on the requirements for Montana-Dakota. The Company will continue to monitor the progress of these changes and assess the potential impacts they may have on its stakeholders, business processes, results of operations, cash flows and disclosures. Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather, as well as impacts associated with commercial and industrial slow-downs, including economic recessions, and energy efficiencies. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among residential and commercial customers. Average consumption among both electric and natural gas customers has tended to decline as more efficient appliances and furnaces are installed, and as the Company has implemented conservation programs. Natural gas weather normalization and decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins, as further discussed in Items 1 and 2 - Business Properties. In December 2022 and January 2023, natural gas prices significantly increased across the Pacific Northwest from multiple price-pressuring events including wide-spread below-normal temperatures and higher natural gas consumption; reduced natural gas flows due to pipeline constraints, including maintenance in West Texas; and historically low regional natural gas storage levels. Natural gas prices stabilized by March 2023. The higher natural gas prices in December 2022 and January 2023 impacted both Intermountain and Cascade, both of which borrowed short-term debt of $125.0 million and $150.0 million, respectively, in January 2023 to finance the increased natural gas costs. To assist in the recovery of higher natural gas costs, Intermountain filed an out-of-cycle purchased gas adjustment with the IPUC that was effective February 1, 2023, and is collecting interest costs associated with short-term borrowing with rates effective October 1, 2023. Effective November 1, 2023, as approved by the WUTC, Cascade started recovery in Washington of these increased gas costs over a period of two years rather than the normal one year period. As of December 2023, Intermountain and Cascade have repaid $80.0 million and $100.0 million of the $125.0 million and $150.0 million short-term debt, respectively. For a discussion of the Company's most recent cases by jurisdiction, see Item 8 - Note 21. 36 MDU Resources Group, Inc. Form 10-K Index Part II In late summer and fall of 2023, electric fuel and purchased power prices increased across Montana-Dakota's integrated system. This was caused by transmission congestion in northwest North Dakota due to delays in additional SPP transmission line build-out, as well as additional load growth in the Bakken region. Electric fuel and purchased power prices remained elevated into November. To assist in the recovery of the higher fuel and purchased power costs, Montana-Dakota filed waiver requests with the NDPSC and SDPUC, which were approved on October 24, 2023 and November 7, 2023, respectively, deferring the increased costs to the annual fuel clause adjustment. In Montana, the waiver request is filed monthly and is unopposed by the MTPSC. On December 22, 2023, MISO filed a complaint letter with SPP regarding concerns related to the coordination of the constraint. Montana-Dakota filed a complaint letter with FERC related to this issue on January 23, 2024. 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 and inflationary pressures to continue. The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the segments to grow their service territory and customer base is affected by regulatory constraints, the economic environment of the markets served, population changes and competition from other energy providers and fuel. The construction of new electric generating facilities, transmission lines and other service facilities is subject to increasing costs and lead times, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. As the industry continues to expand the use of renewable energy sources, the need for additional transmission infrastructure is growing. As part of MISO's long range transmission plan, in August 2022, the Company announced its intent to develop, construct and co-own JETx with Otter Tail Power Company in central North Dakota. On October 6, 2023, the FERC issued an order approving the Company's request for CWIP Incentive Rate and Abandoned Plant Incentive treatment on this project. MDU Resources Group, Inc. Form 10-K 37 Index Part II Earnings overview - The following information summarizes the performance of the electric segment. 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Operating revenues $ 401.2 $ 377.1 $ 349.6 6 % 8 % Operating expenses: Electric fuel and purchased power 107.9 92.0 74.1 17 % 24 % Operation and maintenance 119.6 120.7 124.9 (1) % (3) % Depreciation and amortization 64.2 67.8 66.8 (5) % 1 % Taxes, other than income 16.7 16.9 17.5 (1) % (3) % Total operating expenses 308.4 297.4 283.3 4 % 5 % Operating income 92.8 79.7 66.3 16 % 20 % Other income 5.8 .5 4.6 NM (89) % Interest expense 28.0 28.5 26.7 (2) % 7 % Income before income taxes 70.6 51.7 44.2 37 % 17 % Income tax benefit (1.0) (5.4) (7.7) (81) % (30) % Net income $ 71.6 $ 57.1 $ 51.9 25 % 10 % NM - not meaningful Operating statistics 2023 2022 2021 Revenues (millions) Retail sales: Residential $ 134.1 $ 135.4 $ 123.0 Commercial 164.1 142.7 133.3 Industrial 42.3 43.0 40.5 Other 7.1 7.3 6.8 347.6 328.4 303.6 Other 53.6 48.7 46.0 $ 401.2 $ 377.1 $ 349.6 Volumes (million kWh) Retail sales: Residential 1,180.2 1,226.4 1,164.8 Commercial 2,350.5 1,437.7 1,433.0 Industrial 583.7 596.1 589.4 Other 81.8 83.7 84.4 4,196.2 3,343.9 3,271.6 Average cost of electric fuel and purchased power per kWh $ .024 $ .026 $ .021 2023 compared to 2022 Electric earnings increased $14.5 million as a result of: • Revenue increased $24.1 million. ◦ Largely attributable to: ▪ Higher fuel and purchased power costs of $15.9 million recovered in customer rates and offset in expense, as described below. ▪ Rate relief of $4.4 million in North Dakota and Montana. ▪ Higher data center revenue of $3.4 million, including net transmission. ▪ Higher transmission interconnect upgrades of $2.9 million. ◦ Partially offset by lower retail sales volumes of $2.4 million, driven primarily by lower residential volumes, largely due to cooler weather in the third quarter of the year. Although residential volumes were lower, there was a 25.5 percent increase in volumes overall, which was largely driven by the data center as previously discussed and further discussed in the outlook section. • Electric fuel and purchased power increased $15.9 million, largely the result of higher retail sales volumes, partially offset by lower commodity prices. • Operation and maintenance decreased $1.1 million. ◦ Largely the result of: ▪ Decreased Coyote Station costs of $1.7 million due to the absence of the planned outage in 2022. ▪ Lower materials expense of $500,000, partially due to the closure of Units 1 and 2 at Heskett Station. ◦ Partially offset by increased payroll-related costs of $700,000, which include higher employee incentive accruals. 38 MDU Resources Group, Inc. Form 10-K Index Part II • Depreciation and amortization decreased $3.6 million. ◦ Primarily due to decreased amortization of plant retirement and closure costs of $5.3 million resulting from an extension to the recovery period for these costs, which are recovered in operating revenues, as discussed in Note 12. ◦ Partially offset by increased depreciation of $1.2 million associated with higher property, plant and equipment balances, the result of transmission projects placed in service to improve reliability and update aging infrastructure. • Taxes, other than income were comparable to the same period in the prior year. • Other income increased $5.3 million, primarily resulting from higher returns on the Company's nonqualified benefit plan investments of $4.7 million, as discussed in Note 9, and higher interest income of $1.3 million, largely related to contributions in aid of construction, offset in part by lower AFUDC equity due to higher average debt balance. • Interest expense decreased $500,000, as a result of higher AFUDC debt, largely due to higher rates, partially offset by higher average interest rates. • Income tax benefit decreased $4.4 million. ◦ Largely due to: ▪ Higher income taxes of $4.7 million related to higher taxable income. ▪ Decreased excess deferred income tax amortization. ◦ Partially offset by lower permanent tax adjustments. 2022 compared to 2021 Electric earnings increased $5.2 million as a result of: • Revenue increased $27.5 million. ◦ Largely attributable to: ▪ Higher fuel and purchased power costs of $17.9 million recovered in customer rates and offset in expense, as described below. ▪ Interim rate relief in North Dakota of $5.0 million. ▪ Higher net transmission revenues of $3.9 million, largely from increased investment, and higher transmission interconnect upgrades of $800,000. ▪ Higher retail sales volumes of 2.2 percent, primarily to residential customers, largely due to colder weather in the first and fourth quarters of the year. ◦ Partially offset by: ▪ Lower renewable tracker revenues associated with higher production tax credits offset in expense, as described below. ▪ Lower per unit average rates of $1.0 million related to block rates in certain jurisdictions. • Electric fuel and purchased power increased $17.9 million . ◦ Primarily the result of $17.4 million higher commodity price, including higher recovery of fuel clause adjustments, and increased retail sales volumes. • Operation and maintenance expense decreased $4.2 million. ◦ Primarily due to: ▪ Decreased payroll-related costs, largely $2.8 million related to the Heskett Station and Lewis & Clark Station plant closures and lower incentive accruals of $1.9 million. ▪ Reduced materials costs and contract services from the Heskett Station and Lewis & Clark Station plant closures. ▪ Reduced costs due to the absence of the Big Stone Station outage in 2021. ◦ Partially offset by increased contract services associated with a planned outage at Coyote Station of $2.6 million. • Depreciation and amortization increased $1.0 million, largely resulting from increased property, plant and equipment balances placed in service, mostly related to growth and replacement projects. • Taxes, other than income decreased $600,000, largely as a result of lower coal conversion taxes in certain jurisdictions. • Other income decreased $4.1 million, primarily due to lower returns on the Company's nonqualified benefit plan investments of $4.6 million, as discussed in Note 9, partially offset by higher AFUDC equity largely due to higher rates. • Interest expense increased $1.8 million, largely resulting from $3.2 million due to higher long-term debt balances, partially offset by higher AFUDC debt largely due to higher rates. • Income tax benefit decreased $2.3 million. ◦ Largely due to: ▪ Higher income taxes of $1.8 million related to higher taxable income. ▪ Higher permanent tax adjustments and decreased excess deferred amortization. ◦ Partially offset by higher production tax credits of $1.4 million driven by higher wind production. MDU Resources Group, Inc. Form 10-K 39 Index Part II Earnings overview - The following information summarizes the performance of the natural gas distribution segment. 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Operating revenues $ 1,287.5 $ 1,273.8 $ 971.9 1 % 31 % Operating expenses: Purchased natural gas sold 805.1 816.1 542.0 (1) % 51 % Operation and maintenance 219.7 205.3 194.1 7 % 6 % Depreciation and amortization 95.3 89.4 86.0 7 % 4 % Taxes, other than income 75.2 71.1 60.6 6 % 17 % Total operating expenses 1,195.3 1,181.9 882.7 1 % 34 % Operating income 92.2 91.9 89.2 — % 3 % Other income 20.8 3.3 8.1 NM (59) % Interest expense 57.6 42.2 37.3 36 % 13 % Income before income taxes 55.4 53.0 60.0 5 % (12) % Income tax expense 6.9 7.8 8.4 (12) % (7) % Net income $ 48.5 $ 45.2 $ 51.6 7 % (12) % NM - not meaningful Operating statistics 2023 2022 2021 Revenues (millions) Retail sales: Residential $ 726.1 $ 715.5 $ 548.1 Commercial 441.2 450.9 330.4 Industrial 45.0 41.5 31.1 1,212.3 1,207.9 909.6 Transportation and other 75.2 65.9 62.3 $ 1,287.5 $ 1,273.8 $ 971.9 Volumes (MMdk) Retail sales: Residential 69.3 74.8 65.6 Commercial 47.9 51.0 44.7 Industrial 5.4 5.4 5.0 122.6 131.2 115.3 Transportation sales: Commercial 1.9 2.0 1.9 Industrial 188.4 165.7 172.5 190.3 167.7 174.4 Total throughput 312.9 298.9 289.7 Average cost of natural gas per dk $ 6.57 $ 6.22 $ 4.70 40 MDU Resources Group, Inc. Form 10-K Index Part II 2023 compared to 2022 : Natural gas distribution earnings increased $3.3 million as a result of: • Revenue increased $13.7 million. ◦ Largely from: ▪ Rate relief of $7.9 million in Idaho and Washington, including the excess deferred income tax tariff settlement of $1.1 million in Washington. ▪ Increased revenue-based taxes recovered in rates of $6.1 million that were offset in expense, as described below. ▪ Higher basic service charges of $4.7 million. ▪ Higher transportation revenue of $3.8 million due to 13.5 percent higher volumes, largely higher electric generation. ▪ Approved rate recovery of short-term debt interest expense related to increased gas costs in Idaho of $3.2 million. ▪ Higher nonregulated revenue of $1.7 million, largely higher liquefied natural gas sales. ▪ Recovery of COVID-19 response costs, including bill assistance programs and waived late payment fees, in Oregon of $700,000. ◦ Partially offset by: ▪ Lower purchased gas sold of $10.8 million, recovered in customer rates that was offset in expense, as described below. ▪ A 6.6 percent decrease in retail sales volumes to all customer classes, offset in part by weather normalization and decoupling mechanisms in certain jurisdictions. • Purchased natural gas sold decreased $11.0 million, primarily due to lower volumes of natural gas purchased of $59.8 million, largely offset by higher natural gas costs of $48.7 million as a result of higher market prices. Purchased natural gas sold includes the absence of the prior year disallowance of $845,000 ordered by the MNPUC. • Operation and maintenance increased $14.4 million. ◦ Primarily due to: ▪ Higher payroll-related costs of $12.6 million, primarily higher employee incentive accruals and straight-time payroll ▪ Increased uncollectible accounts expense of $1.6 million, largely due to higher revenue. ▪ Higher insurance expense of $1.0 million. ▪ Higher software related expenses of $900,000. ◦ Partially offset by: ▪ Lower contract services of $1.2 million, largely lower subcontract labor and consulting fees. ▪ Decreased other expenses, including regulatory deferrals, miscellaneous employee expenses, and gain on sale of the Company's customer service center. • Depreciation and amortization increased $5.9 million, primarily resulting from growth and replacement projects placed in service. • Taxes, other than income increased $4.1 million, largely from higher revenue-based taxes of $6.1 million which are recovered in rates, partially offset by lower property taxes due to lower assessed values of $2.3 million. • Other income increased $17.5 million, driven by higher interest income of $11.3 million, largely related to purchased gas costs, and higher returns on the Company's nonqualified benefit plans of $6.9 million, as discussed in Note 9. These increases were offset in part by higher pension and postretirement expense. • Interest expense increased $15.4 million, primarily from higher short-term and long-term debt balances from debt issued in 2023 and 2022 and higher interest rates, partially offset by higher AFUDC debt of $2.6 million, due to higher rates. • Income tax expense decreased $900,000 largely the result of higher permanent tax adjustments, partially offset by higher income before income taxes. 2022 compared to 2021 Natural gas distribution earnings decreased $6.4 million as a result of: • Revenue increased $301.9 million . ◦ Largely from: ▪ Higher purchased natural gas sold of $273.3 million recovered in customer rates that was offset in expense, as described below. ▪ Higher retail sales volumes of 13.7 percent across all customer classes due to colder weather, partially offset by weather normalization and decoupling mechanisms in certain jurisdictions. ▪ Higher revenue-based taxes recovered in rates of $10.1 million that were offset in expense, as described below. ▪ Approved rate relief of $3.6 million in certain jurisdictions and higher pipeline replacement mechanisms of $1.8 million. • Purchased natural gas sold increased $274.1 million. ◦ Primarily due to: ▪ Higher natural gas costs as a result of higher market prices of $198.1 million, including the higher recovery of purchase gas adjustments related to the February 2021 cold weather event and the 2018 Enbridge pipeline rupture. ▪ Higher volumes of natural gas purchased due to increased retail sales volumes. ▪ Purchased natural gas sold includes the disallowance of $845,000 ordered by the MNPUC, as discussed in Note 21. MDU Resources Group, Inc. Form 10-K 41 Index Part II • Operation and maintenance increased $11.2 million. ◦ Primarily due to: ▪ Higher contract services of $6.4 million, primarily higher subcontractor costs. ▪ Higher payroll-related costs, including higher straight-time payroll of $4.7 million, partially offset by lower incentive accruals of $3.3 million. ▪ Higher other costs, partially resulting from inflation, including higher expected credit losses of $1.8 million from higher receivables balances associated with colder weather and higher gas costs; higher software costs of $1.6 million; higher vehicle fuel cost of $1.3 million; and higher office, travel, materials and other miscellaneous employee costs. • Depreciation and amortization increased $3.4 million. ◦ Largely from: ▪ Increased property, plant and equipment balances from growth and replacement projects placed in service. ◦ Partially offset by: ▪ Decreased depreciation rates in certain jurisdictions of $1.0 million. • Taxes, other than income increased $10.5 million, largely resulting from higher revenue-based taxes which are recovered in rates. • Other income decreased $4.8 million primarily related to lower returns on the Company's nonqualified benefit plan investments of $7.0 million, as discussed in Note 9, partially offset by increased interest income. • Interest expense increased $4.9 million, primarily from higher long-term debt balances and interest rates, partially offset by higher AFUDC debt largely due to higher rates. • Income tax expense decreased $600,000 due to lower income taxes of $1.5 million related to lower taxable income, partially offset by higher permanent tax adjustments. Outlook In 2023, the Company experienced rate base growth of 8.5 percent and expects these segments will grow rate base by approximately 7 percent annually over the next five years on a compound basis. Operations are spread across eight states where the Company expects customer growth to be higher than the national average. In 2023 and 2022, these segments experienced retail customer growth of approximately 1.3 percent and 1.6 percent, respectively, 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 benefit from lower natural gas prices through the Company's utilization of storage and fixed price contracts. In 2022, the Company experienced increased natural gas prices across its service areas, and in January 2023, experienced higher natural gas prices in the Pacific Northwest, as previously discussed in Strategy and Challenges. As a result, the Company filed an out-of-cycle cost of gas adjustment in Idaho, which assisted in the timely recovery of these costs, and received approval from the WUTC to recover these increased gas costs over a period of two years rather than the normal one year period. The Company will continue to monitor natural gas prices, as well as oil and natural gas production levels. In May 2022, the Company began construction of Heskett Unit 4, an 88-MW simple-cycle natural gas-fired combustion turbine peaking unit at the existing Heskett Station near Mandan, North Dakota. The in service date has been delayed past 2023 due to unforeseen operational setbacks. While performing start-up testing an incident occurred resulting in damage to the generator field and turbine components. Repairs are ongoing with the in service date now expected in the second quarter of 2024, assuming no further action is needed based on the conclusions of the ongoing root cause analysis, or other unexpected delays. 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. Existing and proposed emissions reduction plans from the EPA could require the owners of Coyote Station to incur significant new costs. If the owners decide to incur such costs, the costs could, dependent on determination by state regulatory commissions on approval to recover such costs from customers, negatively impact the Company's results of operations, financial position and cash flows. The NDDEQ submitted its state implementation plan to the EPA in August 2022. On March 4, 2023, the Company began to provide power for Applied Digital Corporation's data center near Ellendale, North Dakota under an interim electric service agreement approved by the NDPSC, and on June 6, 2023, the NDPSC unanimously approved the Company's electric service agreement request. At full capacity, the data center requires 180 megawatts of electricity, which is the equivalent of about 28 percent of the Company's generation portfolio. The Applied Digital Corporation's load will be purchased from the MISO market and will not impact other customers' power supply. On October 2, 2023, the Company filed with the NDPSC an electric service agreement request to serve an additional data center in its service territory. 42 MDU Resources Group, Inc. Form 10-K Index Part II The Infrastructure Investment and Jobs Act, commonly known as the Bipartisan Infrastructure Law, was enacted in the fourth quarter of 2021 and is providing long-term opportunities by designating funds for investments such as upgrades to electric and grid infrastructure, transportation systems, and electric vehicle infrastructure. The Company is pursuing various opportunities under the Grid Resilience and Innovative Partnerships Program, which is a part of the Infrastructure Investment and Jobs Act, and will continue to monitor additional opportunities from this law. Legislation and rulemaking The Company continues to monitor legislation and rulemaking related to clean energy standards that may impact its segments. Below are some of the specific legislative actions the Company is monitoring. • The EPA released rulemaking under the federal Clean Air Act in the Federal Register on May 23, 2023, amending GHG emission standards for new fossil-fired electric generating units and re-proposing GHG emission guidelines for existing fossil-fired electric generating units. The proposed standards for new natural gas-fired electric generating units have been made more stringent, requiring units that operate more frequently to install carbon capture controls or co-fire with hydrogen. For existing coal and natural gas-fired units operating more frequently and long-term, the EPA’s emissions guidelines include standards equivalent to installation of carbon capture pollution control or co-firing with lower or zero-carbon fuels, such as hydrogen. States must evaluate individual units and develop, adopt, and submit a plan to the EPA which would include emission standards for each individual unit. State plans are required to be submitted to the EPA no later than 24 months after the final rule effective date. The EPA requested comment on the proposed GHG emission standards and guidelines by August 8, 2023, and intends to finalize the rules in 2024. The EPA has not currently proposed GHG emission standards for existing simple cycle combustion turbines and intends to explore setting emission standards in the future for these units. It is unknown at this time what emission limits or controls would be required for each Montana-Dakota owned and jointly owned fossil-fired electric generating unit. Due to the uncertainty of the EPA rulemaking, Montana-Dakota cannot determine the potential financial impact on its operations. • In Oregon, the Climate Protection Program Rule was approved in December 2021, which requires natural gas companies to reduce GHG emissions 50 percent below the baseline by 2035 and 90 percent below the baseline by 2050. Each year, compliance instruments will be distributed to the Company by the Oregon Department of Environmental Quality at no cost and will decline annually in step with the reduction from baseline. The Company intends to meet its obligations through surrendering no cost emissions allowances and will fill remaining compliance obligations by investing in additional customer conservation and energy efficiency programs, purchasing community climate investment credits, and purchasing low carbon fuels such as renewable natural gas. The Company expects the compliance costs for these regulations to be recovered through customer rates. Due to timing of regulatory recovery, future compliance obligation purchases could impact the Company's operating cash flow. For more information about this rule and associated compliance costs, see Items 1 and 2 - Business Properties. Cascade's 2023 Oregon integrated resource plan projects customer bills could increase substantially as a result of the legislation. Projected customer bill impacts are estimates, subject to change as legislation is implemented and compliance begins, as well as, numerous assumptions used in the complex analysis of integrated resource planning. On September 30, 2022, the Company filed a request for the use of deferred accounting for costs related to the rule and began deferring those costs. The OPUC approved the deferred accounting order on June 27, 2023. The Company, along with the other two local natural gas distribution companies in Oregon, filed a lawsuit on March 18, 2022, challenging the Climate Protection Program Rule. The lawsuit was filed on behalf of customers as the Company does not believe the rule accomplishes environmental stewardship in the most effective and affordable way possible. On December 20, 2023, the Oregon Court of Appeals ruled that the Climate Protection Program rules are invalid. On January 22, 2024, the Oregon Department of Environmental Quality issued a news release stating it will not appeal the court decision invalidating the rule. As a result, the Company did not record any associated emissions compliance obligations as of December 31, 2023. The Oregon Department of Environmental Quality announced its intent to begin the process to reinstate the Climate Protection Program in the first quarter of 2024 and expects the process to take about 12 months. • In Washington, the Climate Commitment Act signed into law in May 2021 requires natural gas distribution companies to reduce overall GHG emissions 45 percent below 1990 levels by 2030, 70 percent below 1990 levels by 2040 and 95 percent below 1990 levels by 2050. As directed by the Climate Commitment Act, in September 2022, the Washington DOE published its final rule on the Climate Commitment Act, which was effective on October 30, 2022, and emissions compliance began on January 1, 2023. The Company must demonstrate that they have met GHG emissions reduction goals through a combination of on-site emissions reductions and the use of approved allowances and offsets. Emissions compliance may be achieved through increased energy efficiency and conservation measures, purchased allowances and offsets, and purchases of low carbon fuels. Emissions allowances are allocated by the Washington DOE to the Company at no cost and additional allowances are required to be purchased at auction. Auctions for allowances are held quarterly. The Company intends to meet the first compliance period requirements, in part, by purchasing allowances through auction. The Company expects compliance costs for these regulations will be recovered through customer rates. Due to the timing of regulatory recovery, the purchase of allowances could impact the Company's operating cash flow. For more information about this rule and associated compliance costs, see Items 1 and 2 - Business Properties. MDU Resources Group, Inc. Form 10-K 43 Index Part II Cascade's 2023 Washington integrated resource plan projects customer bills could increase substantially as a result of the legislation. In 2023, related to this legislation, the Company recorded a liability of $66.8 million for environmental compliance obligations and received proceeds of $62.0 million from the sale of the allocated allowances. Projected customer bill impacts are estimates, subject to change as the legislation is implemented and compliance costs begin, as well as, numerous assumptions used in the complex analysis of integrated resource planning. On October 14, 2022, the Company filed a request for the use of deferred accounting for costs related to the rule and began deferring those costs. The WUTC approved the deferred accounting order on February 28, 2023. • On April 22, 2022, the Washington State Building Code Council approved revisions to the state's commercial energy code that will significantly limit the use of natural gas for space and water heating in new and retrofitted commercial and multifamily buildings and proposed the review of similar restrictions in the future for residential buildings. On November 4, 2022, the Washington State Building Code Council adopted new residential codes requiring gas or electric heat pumps for most new space and water heating installations. The Company, along with two other local natural gas distribution companies in Washington, filed a lawsuit on May 22, 2023, challenging these amendments which the Company believes will stifle innovation, increase the cost of housing and energy for our customers, and do not consider the limitations of electric heat pumps in colder climates. On June 1, 2023, the plaintiffs filed a motion for a preliminary injunction to preliminarily enjoin the challenged building code amendments. Oral arguments on the preliminary injunction were held on July 18, 2023. The court denied the preliminary injunction, finding no immediate harm and confirming the building code amendments were not yet in effect due to the stay of 120 days issued by the Washington State Building Code Council. On September 15, 2023, the Washington State Building Code Council voted to delay the implementation of the State Building and Energy Codes until March 15, 2024. Pipeline Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and non-regulated energy-related services, as discussed in Items 1 and 2 - Business Properties. 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 Company completed the following organic growth projects in 2022 and 2023: • In February 2022, the North Bakken Expansion project in western North Dakota was placed in service. The project has capacity to transport 250 MMcf of natural gas per day and can be increased to 625 MMcf per day with additional compression. • In August 2022, the Line Section 7 Expansion project was placed in service and increased system capacity by 6.7 MMcf per day. • In November 2023, the Grasslands South Expansion project was placed in service. The project increased system capacity by 94 MMcf of natural gas per day. • In November 2023, the Line Section 15 Expansion project was placed in service and increased system capacity by 25 MMcf of natural gas per day. 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. The Company continues to actively manage the national supply chain challenges being faced 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. However, supply chain challenges related to electrical equipment have delayed the anticipated in-service date of one of the Company's growth projects as noted in the Outlook section. The segment is also currently experiencing inflationary pressures with increased raw material and contract services costs. The Company expects supply chain challenges and inflationary pressures to continue. 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. 44 MDU Resources Group, Inc. Form 10-K Index Part II Earnings overview - The following information summarizes the performance of the pipeline segment. 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Operating revenues $ 177.6 $ 155.6 $ 142.6 14 % 9 % Operating expenses: Operation and maintenance 70.8 60.9 61.3 16 % (1) % Depreciation and amortization 26.8 26.9 20.5 — % 31 % Taxes, other than income 10.8 12.3 12.7 (12) % (3) % Total operating expenses 108.4 100.1 94.5 8 % 6 % Operating income 69.2 55.5 48.1 25 % 15 % Other income 3.9 1.3 9.4 200 % (86) % Interest expense 13.3 10.1 6.7 32 % 51 % Income before income taxes 59.8 46.7 50.8 28 % (8) % Income tax expense 12.4 10.5 9.7 18 % 8 % Income from continuing operations $ 47.4 $ 36.2 $ 41.1 31 % (12) % Discontinued operations, net of tax* $ (.5) $ (.9) $ (.2) (44) % NM Net income $ 46.9 $ 35.3 $ 40.9 33 % (14) % *Discontinued operations includes interest on debt facilities repaid in connection with the Knife River separation. NM - not meaningful Operating statistics 2023 2022 2021 Transportation volumes (MMdk) 567.2 482.9 471.1 Customer natural gas storage balance (MMdk): Beginning of period 21.2 23.0 25.5 Net injection (withdrawal) 16.5 (1.8) (2.5) End of period 37.7 21.2 23.0 2023 compared to 2022 Pipeline earnings increased $11.6 million as a result of: • Revenues increased $22.0 million. ◦ Driven by increased transportation volumes, largely due to: ▪ Increased contracted volume commitments and a full year of benefit from the North Bakken Expansion project of $9.9 million. ▪ Increased transportation volumes and demand revenue from other organic growth projects placed in service in November 2023 and August 2022. ◦ New rates effective August 1, 2023 of $5.0 million. ◦ Higher storage-related revenues. ◦ Higher non-regulated project revenues of $2.6 million. ◦ Partially offsetting these increases was non-renewal of certain contracts. • Operation and maintenance increased $9.9 million. ◦ Primarily due to: ▪ Higher payroll-related costs of $6.9 million, largely related to higher incentive accruals and benefit-related costs. ▪ Higher non-regulated project costs of $1.2 million directly associated with higher non-regulated project revenues, as previously discussed. ▪ Higher contract services and insurance costs. • Depreciation and amortization decreased $100,000 due to fully depreciated plant, largely offset by higher plant balances associated with growth projects placed in-service, as previously discussed. • Taxes, other than income decreased $1.5 million largely resulting from lower property taxes in Montana. • Other income increased $2.6 million, primarily due to: ◦ Higher returns on the Company's nonqualified benefit plan investments, as discussed in Note 9. ◦ Higher AFUDC of $800,000 for the construction of the company's growth projects. • Interest expense in continuing operations increased $3.2 million, resulting from higher average interest rates and higher debt balances to fund capital expenditures, partially offset by higher AFUDC, as previously discussed. • Income tax expense in continuing operations increased $1.9 million, largely due to higher income before income taxes, partially offset by permanent tax adjustments. MDU Resources Group, Inc. Form 10-K 45 Index Part II 2022 compared to 2021 Pipeline earnings decreased $5.6 million as a result of: • Revenues increased $13.0 million. ◦ Driven by increased transportation volume revenues of $16.4 million, largely due to the North Bakken Expansion project placed in service in February 2022. ◦ Partially offset by: ▪ Lower non-regulated project revenue of $2.3 million. ▪ Lower transmission rates due to expired negotiated contracts converted to tariff rates. • Operation and maintenance decreased $400,000. ◦ Primarily due to: ▪ Lower payroll-related costs of $2.2 million, largely related to lower incentive accruals and benefit-related costs. ▪ Lower non-regulated project costs of $1.3 million directly associated with lower non-regulated project revenues, as previously discussed. ◦ Partially offset by higher legal, maintenance materials and contract services. • Depreciation and amortization increased $6.4 million due to increased property, plant and equipment balances, largely related to the North Bakken Expansion project. • Taxes, other than income decreased $400,000 resulting from lower property taxes of $700,000 in Montana, partially offset by higher property taxes in North Dakota. • Other income decreased $8.1 million, primarily due to: ◦ Lower AFUDC of $7.8 million as a result of the completion of the North Bakken Expansion project placed in service in February 2022. ◦ Lower returns on the Company's nonqualified benefit plan investments, as discussed in Note 9. • Interest expense in continuing operations increased $3.4 million, resulting from interest associated with higher debt balances to fund capital expenditures and lower AFUDC as a result of the North Bakken Expansion project placed in service in February 2022. • Income tax expense in continuing operations increased $800,000, largely a result of a reduction in tax credits, partially offset by lower income before income taxes. Outlook The Company continues to monitor and assess the potential impacts of two FERC draft policy statements issued in the first quarter of 2022. One is the Updated Certificate of Policy Statement, which describes how the FERC will determine whether a new interstate natural gas transportation project is required by public convenience and necessity. It includes increased focus on a project's purpose and need and the environmental impacts; as well as impacts on landowners and environmental justice communities. The second draft policy statement, the Interim GHG Policy Statement, explains how the FERC will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act and Natural Gas Act. 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. On December 2, 2023, the EPA issued a prepublication version of its final rule to update, strengthen and expand standards intended to significantly reduce GHG emissions and other air pollutants from emission sources in the oil and natural gas industries. The standards will apply to various sources of GHG emissions including natural gas compressors, process controllers, natural gas driven pumps, storage vessels, natural gas wells, fugitive emissions components and super-emitter events. The final rule has not been published in the Federal Register to date. Additionally, the EPA is revising the current GHG reporting rules to improve the calculation, monitoring and reporting of GHG data and incorporate provisions from the IRA. The first of these revisions was published in the Federal Register on August 1, 2023. The Company continues to monitor and assess the proposed rules and the potential impacts they may have on its business processes, current and future projects, results of operations and disclosures. 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 demand. The completion of organic growth projects has contributed to higher volumes of natural gas the Company transports through its system. Associated natural gas production in the Bakken fell during the COVID-19 pandemic delaying previously forecasted production growth. The production delay, along with the long-term contractual commitments on the North Bakken Expansion project placed in service in February 2022, negatively impacted customer renewal of certain contracts. Natural gas production has since rebounded, and is currently at record levels and the Company expects gradual increases in oil well drilling activity over the next two years. Bakken natural gas production outlook remains positive with continued growth expected due to new oil wells and increasing gas to oil ratios. Increases in national and global natural gas supply has 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 opportunity for industrial supply and demand related projects and seasonal pricing differentials provide opportunities for natural gas storage services. The Company continues to focus on improving existing operations and growth opportunities through organic projects in all areas in which it operates, which includes additional projects with local distribution companies, Bakken area producers and industrial customers in various stages of development. 46 MDU Resources Group, Inc. Form 10-K Index Part II In July 2021, the Company announced plans for a natural gas pipeline expansion project in eastern North Dakota. The Wahpeton Expansion project consists of approximately 60 miles of pipe and ancillary facilities and is designed to increase capacity by 20 MMcf per day, which is supported by long-term customer agreements with Montana-Dakota and its utility customers. On May 27, 2022, the Company filed with FERC its application for the project and received FERC's approval on October 19, 2023. Construction is anticipated to begin in the second quarter of 2024 with an estimated completion in late 2024. On September 19, 2022, the Company filed with the FERC its prior notice application for its 2023 Line Section 27 expansion project. This project consists of a new compressor station and ancillary facilities and is designed to increase capacity by 175 MMcf per day, which is supported by a long-term customer agreement. Construction began in the second quarter of 2023, with an anticipated completion date in the first quarter of 2024. Supply chain challenges related to electrical equipment have impacted the project's schedule, resulting in a delay from the original anticipated in-service date of late 2023. Construction is expected to begin in the second quarter of 2024 on the Line Section 28 expansion project, to serve a natural gas-fired power plant in northwestern North Dakota which will add 137 million cubic feet of natural gas transportation capacity per day. This project is supported by a long-term negotiated customer agreement and is expected to be in service in the third quarter of 2024. See Capital Expenditures within this section for information on the expenditures related to these growth projects. Construction Services Strategy and challenges The construction services segment provides electrical, mechanical and transmission and distribution specialty contracting services, as discussed in Items 1 and 2 - Business Properties. The construction services segment focuses on safely executing projects; providing a superior return on investment by building new and strengthening existing customer relationships; ensuring quality service; effectively controlling costs; retaining, developing and recruiting talented employees; growing through organic and strategic acquisition opportunities; and focusing efforts on projects that will permit higher margins while properly managing risk. The growth experienced by the segment in recent years is due in part to the project awards in the markets served and the ability to support national customers in most of the regions in which it operates. The construction services segment faces challenges, which are not under direct control of the business, in the markets in which it operates, including those described in Item 1A - Risk Factors. These factors, and those noted below, have caused fluctuations in revenues, gross margins and earnings in the past and are likely to cause fluctuations in the future. • Revenue mix and impact on margins. The mix of revenues based on the types of services the segment provides can impact margins as certain industries and services provide higher margin opportunities. Larger or more complex projects typically result in higher margin opportunities since the segment assumes a higher degree of performance risk and there is greater utilization of the segment's resources for longer construction timelines. However, larger or more complex projects can have a higher risk of regulatory and seasonal or cyclical delay. Project schedules fluctuate, which can affect the amount of work performed in a given period. Smaller or less complex projects typically have a greater number of companies competing for them, and competitors at times may be more aggressive on pricing when pursuing available work. A greater percentage of smaller scale or less complex work in a given period could negatively impact margins due to the inefficiency of transitioning between a greater number of smaller projects versus continuous production on a few larger projects. • Project variability and performance. Margins for a single project may fluctuate period to period due to changes in the volume or type of work performed, the pricing structure under the project contract or job productivity. Productivity and performance on a project can vary period to period based on a number of factors, including unexpected project difficulties; unexpected project site conditions; project location, including locations with challenging operating conditions or difficult geographic characteristics; whether the work is on an open or encumbered right of way; inclement weather or severe weather events; environmental restrictions or regulatory delays; political or legal challenges related to a project; and the performance of third parties. In addition, the type of contract can impact the margin on a project. Under fixed-price contracts, which are more common with larger or more complex projects, the segment assumes risk related to project estimates versus actual execution. Revenues under this type of contract can vary, sometimes significantly, from original projects due to additional project complexity; timing uncertainty or extended bidding; extended regulatory or permitting processes; and other factors, which can result in a reduction in profit or losses on a project. • Subcontractor work and provision of materials. Some work under project contracts is subcontracted out to other companies and margins on subcontractor work is generally lower than work performed by the Company. Increased subcontractor work in a given period may therefore result in lower margins. In addition, inflationary or other pressures may increase the cost of materials under fixed-price contracts and may result in decreased margins on the project. The Company has worked to implement provisions in project contracts to allow for the pass-through of inflationary costs to customers where feasible and will continue to do so to mitigate the impacts. MDU Resources Group, Inc. Form 10-K 47 Index Part II The segment's management continually monitors its operating margins and has been proactive in attempting to mitigate the inflationary impacts seen across the United States. The segment is currently experiencing continued labor constraints and material costs, as well as impacts from delays in the national supply chain. The segment is working with suppliers and providers of goods and services in advance of construction to secure pricing and reduce delays for goods and services. The inflationary costs and national supply chain challenges experienced by the segment have increased costs but have not had significant impacts to the procurement of project materials. Such volatility and inflationary pressures may continue to have an impact on the segment's margins, including fixed-price construction contracts that are particularly vulnerable to the volatility of energy and material prices. These increases are partially offset by mitigation measures implemented by the Company, including escalation clauses in contracts, pre-purchased materials and other cost savings initiatives. The segment also continues recruitment and retention efforts to attract and retain employees. Accordingly, operating results in any particular period may not be indicative of the results that can be expected for any other period. The need to ensure available specialized labor resources for projects also drives strategic relationships with customers and project margins. Challenges faced by the Company to ensure available specialized labor resources include an aging workforce and labor availability issues, as well as increasing duration and complexity of customer capital programs. Most of the markets the segment operates in have experienced labor shortages which in some cases have caused increased labor-related costs. The Company continues to monitor the labor markets and expects labor costs to continue to increase based on increases included in the collective bargaining agreements and, to a lesser extent, the recent escalated inflationary environment in the United States. Due to these and other factors, the Company believes overall customer and competitor demand for labor resources will continue to increase. In order to meet customer demand, the Company is planning for future labor needs, increasing recruiting efforts and developing labor both locally and nationally. Earnings overview - The following information summarizes the performance of the construction services segment. 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Operating revenues $ 2,854.4 $ 2,699.2 $ 2,051.6 6 % 32 % Cost of sales: Operation and maintenance 2,426.1 2,325.9 1,725.5 4 % 35 % Depreciation and amortization 18.3 16.9 15.8 8 % 7 % Taxes, other than income 88.1 80.4 62.4 10 % 29 % Total cost of sales 2,532.5 2,423.2 1,803.7 5 % 34 % Gross profit 321.9 276.0 247.9 17 % 11 % Selling, general and administrative expense: Operation and maintenance 121.4 101.5 92.9 20 % 9 % Depreciation and amortization 4.9 4.6 4.5 7 % 2 % Taxes, other than income 5.1 5.3 4.8 (4) % 10 % Total selling, general and administrative expense 131.4 111.4 102.2 18 % 9 % Operating income 190.5 164.6 145.7 16 % 13 % Other income 9.0 7.3 2.6 23 % 181 % Interest expense 10.1 .2 (.1) NM NM Income before income taxes 189.4 171.7 148.4 10 % 16 % Income tax expense 47.0 42.2 36.2 11 % 17 % Income from continuing operations 142.4 129.5 112.2 10 % 15 % Discontinued operations, net of tax* (5.2) (4.7) (2.8) 11 % 68 % Net income $ 137.2 $ 124.8 $ 109.4 10 % 14 % *Discontinued operations includes interest on debt facilities repaid in connection with the Knife River separation. NM - not meaningful 48 MDU Resources Group, Inc. Form 10-K Index Part II Operating Statistics Revenues Gross profit (loss) Business Line 2023 2022 2021 2023 2022 2021 (In millions) Electrical & mechanical Commercial $ 1,204.0 $ 1,082.5 $ 553.2 $ 129.1 $ 105.2 $ 59.8 Industrial 473.3 405.7 457.5 45.3 43.4 51.3 Institutional 262.4 215.5 123.1 16.3 3.8 6.2 Renewables 55.4 151.1 12.3 3.5 (0.6) 1.2 Service & other 139.8 143.0 188.4 19.6 19.8 25.1 2,134.9 1,997.8 1,334.5 213.8 171.6 143.6 Transmission & distribution Utility 677.5 645.1 630.5 105.1 100.3 92.4 Transportation 57.1 72.3 103.1 3.0 4.1 11.9 734.6 717.4 733.6 108.1 104.4 104.3 Intrasegment eliminations (15.1) (16.0) (16.5) — — — $ 2,854.4 $ 2,699.2 $ 2,051.6 $ 321.9 $ 276.0 $ 247.9 2023 compared to 2022 Construction services earnings increased $12.4 million as a result of: • Revenues increased $155.2 million. ◦ Largely due to: ▪ Increased electrical and mechanical revenues as a result of: ◦ Higher commercial revenues driven largely by a $102.2 million increase in hospitality projects and $49.9 million in data center projects, both due to higher workloads, partially offset by lower general commercial and mechanical workloads of $23.0 million. ◦ Higher industrial revenues on high-tech and government projects of $66.4 million and $15.5 million, respectively, partially offset by lower industrial and low voltage projects of $12.9 million. ◦ Institutional revenues increased $46.8 million, largely the result of higher project workloads in the healthcare market. ▪ Increased transmission and distribution revenues as a result of higher utility workloads for distribution projects of $71.0 million, transmission projects of $26.0 million, and gas and underground projects of $25.1 million. These increases were largely offset by lower workloads on electrical projects of $94.6 million. ◦ Partially offset by: ▪ Lower renewable revenues of $95.7 million due to timing of projects. ▪ Lower transportation revenues of $15.2 million, primarily from lower workloads on street lighting, government, and electrical projects. These decreases were partially offset by higher traffic signalization projects. • Gross profit increased $45.9 million. ◦ Largely due to the increased electrical and mechanical revenues previously discussed. ◦ Increased also as a result of margin improvement due to project mix and efficiency in labor and materials costs compared to the prior year. • Selling, general and administrative expense increased $20.0 million resulting from higher payroll-related costs of $7.3 million, higher reserves for uncollectible accounts on certain projects of $6.0 million, increased office expense, and higher professional services related to operational activity. • Other income increased $1.7 million, primarily related to the Company's joint ventures. • Interest expense in continuing operations increased $9.9 million due to higher working capital needs and higher interest rates. • Income tax expense in continuing operations increased $4.8 million as a result of higher income before income taxes. MDU Resources Group, Inc. Form 10-K 49 Index Part II 2022 compared to 2021 Construction services earnings increased $15.4 million as a result of: • Revenues increased $647.6 million. ◦ Largely due to: ▪ Increased electrical and mechanical revenues, partially as a result of inflationary pressures as well as: ◦ Higher commercial revenues driven largely by a $251.5 million increase in hospitality projects due to the progress on large projects, a $121.8 million increase in data center projects driven by both the number of and progress on projects and an increase in general commercial projects as a result of project mix and progression of contracts. ◦ Higher renewable revenues from the timing of and progress on projects. ◦ Higher institutional revenues largely the result of increased activity and progress on projects from education projects of $26.0 million, healthcare projects of $24.1 million and government projects. ▪ Increased utility revenues for electrical projects of $37.5 million, underground projects of $24.5 million, distribution projects of $12.7 million, telecommunications projects of $7.0 million and substation projects, with each sector being driven by higher customer demand. These increases were partially offset by lower transmission and storm work projects. ◦ Partially offset by: ▪ Lower industrial revenues driven by decreased demand for maintenance, high-tech and refinery projects and lower service revenues driven by decreased demand for the repair and maintenance of electrical and mechanical projects. ▪ Lower transportation revenues, primarily from lower customer demand for street lighting projects of $39.8 million. • Gross profit increased $28.1 million. ◦ Largely due to the increased electrical and mechanical revenues previously discussed. ◦ Partially offset by higher operating costs related to inflationary pressures, including labor, materials and equipment costs. • Selling, general and administrative expense increased $9.2 million resulting from higher payroll-related costs of $5.7 million, increased expected credit losses of $2.4 million due to changes in estimates during 2021 and higher office expenses. • Other income increased $4.7 million, primarily related to the Company's joint ventures. • Interest expense in continuing operations increased $300,000 due to higher working capital needs and higher interest rates. • Income tax expense in continuing operations increased $6.0 million as a result of higher income before income taxes. Outlook On November 2, 2023, the Company announced its intent to pursue a tax-free spinoff of its wholly owned construction services business, MDU Construction Services. The Company's board of directors believes a tax-free spinoff of the construction services business supports the Company's goal of enhancing value for stockholders by becoming a pure-play regulated energy delivery company. Some of the construction services projects are publicly funded, which is highly dependent on federal and state funding. The American Rescue Plan provides $1.9 trillion in COVID-19 relief funding for states, schools and local government including broadband infrastructure. States are beginning to move forward with allocating these funds based on federal criteria and state needs, and in some cases, funding of infrastructure projects could positively impact the segment. Additionally, the Infrastructure Investment and Jobs Act, was enacted in the fourth quarter of 2021 and is providing long-term opportunities by designating funds for investments for upgrades to electric and grid infrastructure, transportation systems, airports and electric vehicle infrastructure, all industries this segment supports. In addition, the IRA provides $369 billion in new funding for clean energy programs. These programs include new tax incentives for solar, battery storage and hydrogen development along with funding to expand the production of electric vehicles and the build out of infrastructure to support electric vehicles. The Company will continue to monitor the implementation of these legislative items. The Company continues to have bidding opportunities in the specialty contracting markets in which it operated in during 2023, as evidenced by the segment's backlog. Although bidding remains highly competitive in all areas, the Company expects the segment's relationship with existing customers, skilled workforce, quality of service and effective cost management will continue to provide a benefit in securing and executing profitable projects in the future. The Company has also seen rapidly growing needs for services across the electric vehicle charging, solar generation and energy storage markets that complement existing renewable projects performed by the Company. Backlog consists of the uncompleted portion of services to be performed under job-specific contracts. Contracts are subject to delay, default or cancellation, and contracts in our backlog are subject to changes in the scope of services to be provided, as well as adjustments to the costs. Backlog may also be affected by project delays or cancellations resulting from weather conditions, external market factors and economic factors beyond our control, among other things. Accordingly, there is no assurance that backlog will be realized. As of December 31, 2023, the Company has not experienced any material impacts related to customer notices indicating that they no longer wish to proceed with the planned projects that have been included in backlog. The timing of contract awards, duration of large new contracts and the mix of services can significantly affect backlog. Backlog at any given point in time may not accurately represent the revenue or net income that is realized in any period. Also, the backlog as of the end of the year may not be indicative of the Operating revenues and Net income expected to be earned in the following year and should not be relied upon as a standalone indicator of future Operating revenues or Net income. Factors noted in Item 1A - Risk Factors can cause revenues to be realized in periods and at levels that are different from originally projected. 50 MDU Resources Group, Inc. Form 10-K Index Part II Subject to the foregoing discussion, the construction services segment's backlog at December 31 was as follows: 2023 2022 (In millions) Electrical & mechanical $ 1,686 $ 1,861 Transmission & distribution 325 270 $ 2,011 $ 2,131 The decrease in backlog at December 31, 2023, as compared to backlog at December 31, 2022, was largely attributable to the progress of completion on certain electrical and mechanical projects within industrial, renewables and commercial markets. This decrease in backlog has been partially offset by an increase in transmission and distribution project awards in both the transportation and utility markets. Other 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Operating revenues $ 8.0 $ 5.8 $ 4.6 38 % 26 % Operating expenses: Operation and maintenance 22.5 22.9 18.2 (2) % 26 % Depreciation and amortization 4.1 4.4 4.7 (7) % (6) % Taxes, other than income .1 .2 — (50) % 100% Total operating expenses 26.7 27.5 22.9 (3) % 20 % Operating loss (18.7) (21.7) (18.3) (14) % (19) % Gain on tax-free exchange of retained shares in Knife River 186.6 — — NM NM Other income (expense) 15.7 (.6) 1.1 NM (155) % Interest expense 18.9 .3 .2 NM 50 % Income (loss) before income taxes 164.7 (22.6) (17.4) NM (30) % Income tax benefit (5.8) (5.4) (3.1) 7 % (74) % Income (loss) from continuing operations 170.5 (17.2) (14.3) NM (20) % Discontinued operations, net of tax (60.0) 122.3 138.6 (149) % (12) % Net income $ 110.5 $ 105.1 $ 124.3 5 % (15) % NM - not meaningful On May 31, 2023, the Company completed the separation of Knife River, its former construction materials and contracting segment, into a new publicly traded company. As a result of the separation, the historical results of operations for Knife River are shown in discontinued operations, net of tax, except for allocated general corporate overhead costs of the company, which do not meet the criteria for income (loss) from discontinued operations. Also included in discontinued operations are strategic initiative costs associated with the separation of Knife River. Also included in Other is insurance activity at the Company's captive insurer and general and administrative costs and interest expense previously allocated to the exploration and production and refining businesses that do not meet the criteria for income (loss) from discontinued operations. In November 2023, the Company completed a tax-free exchange of its 5.7 million shares of its retained interest in Knife River, which is reflected in Other. This tax-free exchange resulted in a gain of $186.6 million. Other also benefited from higher interest income. Partially offsetting these items were higher interest expense, primarily related to debt issued in connection with the Knife River separation. Other also benefited from lower insurance claims experience in 2023 at the captive insurer compared to 2022. During 2022, Other experienced higher operation and maintenance expense primarily related to costs that do not meet the criteria for income (loss) from discontinued operations, including costs associated with other strategic initiatives and general corporate overhead costs allocated to Knife River, partially offset by a reduction in the estimated losses recorded at the captive insurer. Other was positively impacted by higher premiums included in operating revenues in 2022 for the captive insurer compared to 2021. Discontinued operations reflect the historical results of operations for Knife River, as previously discussed. MDU Resources Group, Inc. Form 10-K 51 Index Part II 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: Years ended December 31, 2023 2022 2021 (In millions) Intersegment transactions: Operating revenues $ 71.4 $ 69.7 $ 65.9 Operation and maintenance 9.3 11.5 7.0 Purchased natural gas sold 62.1 58.2 58.9 Other income 13.6 0.6 0.1 Interest expense 13.6 0.6 0.1 For more information on intersegment eliminations, see Item 8 - Note 18. Liquidity and Capital Commitments At December 31, 2023, the Company had cash, cash equivalents and restricted cash of $77.0 million and available borrowing capacity of $525.8 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 and equity securities if necessary. Cash flows Years ended December 31, 2023 2022 2021 (In millions) Net cash provided by (used in) Operating activities $ 332.6 $ 510.0 $ 495.8 Investing activities (540.7) (638.9) (885.9) Financing activities 204.6 155.2 384.7 Increase (decrease) in cash, cash equivalents and restricted cash (3.5) 26.3 (5.4) Cash, cash equivalents and restricted cash -- beginning of year 80.5 54.2 59.6 Cash, cash equivalents and restricted cash -- end of year $ 77.0 $ 80.5 $ 54.2 Operating activities 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Income from continuing operations $ 480.4 $ 250.8 $ 242.5 $ 229.6 $ 8.3 Adjustments to reconcile net income to net cash provided by operating activities 22.5 243.1 222.0 (220.6) 21.1 Changes in current assets and current liabilities, net of acquisitions: Receivables 110.4 (330.8) (75.4) 441.2 (255.4) Inventories (27.6) (15.6) .1 (12.0) (15.7) Other current assets (52.9) (9.4) (67.4) (43.5) 58.0 Accounts payable (76.7) 172.7 25.5 (249.4) 147.2 Other current liabilities 67.0 7.6 3.5 59.4 4.1 Pension and postretirement benefit plan contributions (7.6) (.1) (.1) (7.5) — Other noncurrent changes (22.8) (10.7) (51.7) (12.1) 41.0 Net cash provided by continuing operations 492.7 307.6 299.0 185.1 8.6 Net cash (used in) provided by discontinued operations (160.1) 202.4 196.8 (362.5) 5.6 Net cash provided by operating activities $ 332.6 $ 510.0 $ 495.8 $ (177.4) $ 14.2 52 MDU Resources Group, Inc. Form 10-K Index Part II The changes in cash flows from operating activities generally follow the results of operations as discussed in Business Segment Financial and Operating Data and are affected by changes in working capital. The decrease in cash flows provided by operating activities in 2023 from 2022 was largely driven by increased cash used in discontinued operations, primarily cash used at Knife River in the five months of 2023 compared to cash provided by Knife River in the twelve months of 2022 and higher costs incurred in 2023 associated with the Knife River separation. Also contributing were the payment of increased natural gas costs and the purchase/sale of environmental allowances in 2023, as discussed in Note 7, all at the natural gas distribution business. Partially offsetting these items was higher cash from receivables due to the timing of the job activity, billing fluctuations and higher cash collections at the construction services business and the timing of collection of accounts receivable from customers at the natural gas distribution business. The increase in cash flows provided by operating activities in 2022 from 2021 was driven by higher 2022 accounts payable for natural gas purchases due to higher natural gas prices and colder weather at the natural gas distribution business. In addition, an increase in cash from other current assets contributed to the improvement, largely related to a 2021 income tax overpayment that was utilized in 2022. Partially offsetting the increase was higher working capital needs at the construction services business due to fluctuations in job activity resulting in higher receivables in the period, as well as lower collections of accounts receivable compared to 2021, offset in part by increased accounts payable. Investing activities 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Capital expenditures $ (519.7) $ (478.4) $ (485.2) $ (41.3) $ 6.8 Acquisitions, net of cash acquired — — (2.5) — 2.5 Net proceeds from sale or disposition of property 16.5 11.3 14.6 5.2 (3.3) Cost of removal, net of salvage value 1.1 (11.8) (11.4) 12.9 (.4) Investments 16.3 (4.1) (3.1) 20.4 (1.0) Net cash used in continuing operations (485.8) (483.0) (487.6) (2.8) 4.6 Net cash used in discontinued operations (54.9) (155.9) (398.3) 101.0 242.4 Net cash used in investing activities $ (540.7) $ (638.9) $ (885.9) $ 98.2 $ 247.0 The decrease in cash used in investing activities in 2023 from 2022 was primarily the result of lower cash used in discontinued operations in the five months of 2023 versus twelve months of 2022, higher proceeds from investments in 2023, and the absence of 2022 plant removal costs at the electric business. This was partially offset by higher capital expenditures at the pipeline business for its expansion projects and increased capital expenditures at the natural gas distribution business, primarily higher natural gas distribution system improvements related to increased capacity, largely offset by lower capital expenditures for electric production and transmission projects. The decrease in cash used in investing activities in 2022 from 2021 was primarily the result of lower cash used in discontinued operations for acquisition activity. Decreased capital expenditures at the pipeline business as a result of the North Bakken Expansion project being placed in service in February 2022 were mostly offset by increased capital expenditures at the natural gas distribution business for higher natural gas distribution projects, including natural gas mains and meters, and at the electric business for increased electric production projects, including the construction of Heskett Unit 4 and the repower of Diamond Willow. Financing activities 2023 vs. 2022 2022 vs. 2021 Years ended December 31, 2023 2022 2021 Variance Variance (In millions) Issuance of short-term borrowings $ 810.0 $ 38.5 $ 50.0 $ 771.5 $ (11.5) Repayment of short-term borrowings (460.9) — (100.0) (460.9) 100.0 Issuance of long-term debt 726.6 373.0 272.0 353.6 101.0 Repayment of long-term debt (793.0) (65.8) (24.8) (727.2) (41.0) Debt issuance costs (2.5) (1.1) (.9) (1.4) (.2) Proceeds from issuance of common stock — (.1) 88.8 .1 (88.9) Dividends paid (161.3) (176.9) (171.4) 15.6 (5.5) Repurchase of common stock (4.8) (7.4) (6.7) 2.6 (.7) Tax withholding on stock-based compensation (3.0) (4.9) (4.1) 1.9 (.8) Net cash provided by continuing operations $ 111.1 $ 155.3 $ 102.9 (44.2) 52.4 Net cash provided by (used in) discontinued operations 93.5 (0.1) 281.8 93.6 (281.9) Net cash provided by financing activities $ 204.6 $ 155.2 $ 384.7 $ 49.4 $ (229.5) MDU Resources Group, Inc. Form 10-K 53 Index Part II The increase in cash provided by financing activities in 2023 from 2022 was primarily due to higher issuance of short-term borrowings associated with the debt for equity exchange of the Knife River retained shares, as well as the issuance of short-term borrowings at the natural gas distribution business to fund higher natural gas costs. Also contributing were higher issuance of long-term debt at the Company to replace the Centennial debt repayment and to fund capital expenditures and increased cash provided by discontinued operations. Partially offsetting the increase was higher repayments of short-term and long-term debt at the construction services and natural gas distribution businesses. In addition, due to the Knife River separation, Centennial repaid all of its outstanding debt in the second quarter of 2023, which was facilitated by the Knife River repayment and the Company entering into various new debt instruments. Refer to Note 3 for additional information related to the repayment of debt associated with the Knife River separation. Refer to Note 10 for additional information related to the short-term debt related to the retained shares of Knife River. The decrease in cash provided by financing activities in 2022 from 2021 was largely the result of increased repayment and decreased issuance of long-term debt in discontinued operations and the absence of the issuance of common stock under the Company's "at-the-market" offering during 2022, as discussed in Note 13. Partially offsetting these items were increased issuance of short-term debt as long-term debt replaced short-term debt in preparation of the separation of Knife River, the absence of a 2021 repayment of short-term borrowings at Montana-Dakota, and the increased issuance of long-term debt at the construction services business as a result of higher working capital needs. Defined benefit pension plans The Company has noncontributory qualified defined benefit pension plans for certain employees. Plan assets consist of investments in equity and fixed-income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the pension plans. Actuarial assumptions include assumptions about the discount rate and expected return on plan assets. For 2023, the Company assumed a long-term rate of return on its qualified defined pension plan assets of 6.5 percent. Due to market performance in the equity and fixed-income markets, the Company experienced an increase in the qualified defined pension plan assets. Differences between actuarial assumptions and actual plan results are deferred and amortized into expense when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. Therefore, this change in asset values will be reflected in future expenses of the plans beginning in 2024. The funded status of the plans improved $9.2 million, primarily due to the increase in plan assets, as discussed previously. At December 31, 2023, the pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $27.0 million. Pretax pension income reflected in the Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021, was $580,000, $2.3 million and $1.7 million, respectively. The Company's pension expense is currently projected to be approximately $800,000 in 2024. Funding for the pension plans is actuarially determined. The Company expects to contribute the minimum funding requirement of $3.3 million in 2024. There were no minimum required contributions for the years ended December 31, 2023, 2022, or 2021 due to an additional contribution of $20.0 million in 2019, which created prefunding credits that were used in future periods. For more information on the Company's pension plans, see Item 8 - Note 19. Capital expenditures The Company's capital expenditures for 2021 through 2023 and as anticipated for 2024 through 2026 are summarized in the following table. Actual (a) Estimated 2021 2022 2023 (b) 2024 2025 2026 (In millions) Capital expenditures: Electric $ 82 $ 134 $ 110 $ 113 $ 154 $ 199 Natural gas distribution 170 240 275 337 301 288 Pipeline 235 62 116 107 77 42 Construction services (c) 29 36 35 52 — — Other 2 3 1 3 3 3 Total capital expenditures $ 518 $ 475 $ 537 $ 612 $ 535 $ 532 (a) Capital expenditures for 2023, 2022 and 2021 include noncash transactions such as capital expenditure-related accounts payable and AFUDC totaling $13.1 million, $(3.8) million and $30.6 million, respectively. (b) 2023 capital expenditures were funded by internal sources, long-term debt issuances and borrowings under credit facilities and issuance of commercial paper of the Company and its subsidiaries. (c) Assumes proposed tax-free spinoff is completed in late 2024. 54 MDU Resources Group, Inc. Form 10-K Index Part II Planned utility investments in the Company's estimated capital expenditures for 2024 through 2026 include construction of electric transmission lines and substations, as well as natural gas delivery infrastructure, to serve a customer base that is expected to continue growing at 1 percent to 2 percent annually over the next five years; construction of JETx, a MISO approved project, in partnership with Otter Tail Power Company; and replacing and modernizing certain existing electric and natural gas utility infrastructure to ensure continued safe and reliable service to customers. At the pipeline business, the Company will focus on system growth to expand natural gas transmission capacity. A number of projects are included in the planned investments, including the Wahpeton Expansion project in North Dakota that is expected to be constructed in 2024. Planned investments at the construction services business include normal replacements and upgrades of the equipment that is used in the transmission and distribution, and electrical and mechanical services the company performs. For more information on the Company's growth projects, see Business Segment Financial and Operating Data. Other estimated capital expenditures for the years 2024 through 2026 include those for: • System upgrades • Routine replacements • Service extensions • Routine equipment maintenance and replacements • Buildings, land and building improvements • Pipeline and natural gas storage projects • Power generation and transmission opportunities • Environmental upgrades • Other growth opportunities 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 estimates in the preceding table. The Company continuously monitors its capital expenditures for project delays and changes in economic viability and adjusts as necessary. It is anticipated that all of the funds required for capital expenditures for the years 2024 through 2026 will be funded by various sources, including internally generated funds; credit facilities and commercial paper of the Company and its subsidiaries, as described later; and issuance of debt and equity securities if necessary. 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's subsidiaries contain restrictive and financial covenants and cross-default provisions. In order to borrow under the respective debt instruments, the subsidiary companies must be in compliance with the applicable covenants and certain other conditions, all of which the subsidiaries, as applicable, were in compliance with at December 31, 2023. In the event the subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. As of December 31, 2023, the Company had investment grade credit ratings at all entities issuing debt. For more information on the covenants, certain other conditions and cross-default provisions, see Item 8 - Note 10. The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries at December 31, 2023: Company Facility Facility Limit Amount Outstanding Letters of Credit Expiration Date (In millions) Montana-Dakota Utilities Co. Commercial paper/Revolving credit agreement (a) $ 200.0 $ 144.2 $ — 10/18/28 Cascade Natural Gas Corporation Revolving credit agreement $ 100.0 (b) $ 15.4 $ 25.0 (c) 11/30/27 Intermountain Gas Company Revolving credit agreement $ 100.0 (d) $ 30.7 $ — 10/13/27 MDU Resources Group, Inc. Revolving credit agreement $ 150.0 $ — $ — 5/29/24 MDU Resources Group, Inc. Revolving credit agreement $ 200.0 (e) $ — $ 8.9 5/31/28 (a) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Montana-Dakota on stated conditions, up to a maximum of $250.0 million). At December 31, 2023, there were no amounts outstanding under the revolving credit agreement. (b) Certain provisions allow for increased borrowings, up to a maximum of $125.0 million. (c) Outstanding letter(s) of credit reduce the amount available under the credit agreement. (d) Certain provisions allow for increased borrowings, up to a maximum of $125.0 million. (e) Certain provisions allow for increased borrowings, up to a maximum of $250.0 million. MDU Resources Group, Inc. Form 10-K 55 Index Part II On April 25, 2023, Knife River issued $425.0 million of senior notes, pursuant to an indenture, due in 2031 to qualified institutional buyers. Knife River also entered into a new credit agreement which provided a revolving credit facility in an initial amount of up to $350.0 million and a senior secured term loan facility in an amount up to $275.0 million. The net proceeds from the notes offering, revolving credit facility and the term loan were used to repay $825.0 million of Knife River's intercompany obligations owed to Centennial. Centennial used the entirety of these proceeds from Knife River to repay a portion of its existing third-party indebtedness. Centennial repaid the remainder of its outstanding debt in the second quarter of 2023 with proceeds from various new debt instruments entered into by the Company. The Montana-Dakota commercial paper program is supported by a revolving credit agreement. While the amount of commercial paper outstanding does not reduce available capacity under the revolving credit agreement, Montana-Dakota does not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreement. The commercial paper and revolving credit agreement borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of certain operations of Montana-Dakota. Total equity as a percent of total capitalization was 55 percent at December 31, 2023 and 54 percent at December 31, 2022, which includes discontinued operations. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, excluding debt in discontinued operations and including short-term borrowings and long-term debt due within 12 months, plus total equity. Management believes this ratio is an indicator of how the Company is financing its operations, as well as its financial strength. Montana-Dakota On October 18, 2023, Montana-Dakota amended and restated its revolving credit agreement to increase the borrowing capacity to $200.0 million and extend the maturity date to October 18, 2028. Montana-Dakota's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Historically, downgrades in credit ratings have not limited, nor are currently expected to limit, Montana-Dakota's ability to access the capital markets. If Montana-Dakota were to experience a downgrade of its credit ratings in the future, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings. Prior to the maturity of the credit agreement, Montana-Dakota expects that it will negotiate the extension or replacement of this agreement. If Montana-Dakota is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility become too expensive, which Montana-Dakota does not currently anticipate, it would seek alternative funding. Cascade Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments. On January 20, 2023, Cascade entered into a $150.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of January 19, 2024. On December 5, 2023, Cascade paid down $100.0 million of the outstanding balance, with the final $50.0 million repayment made on January 19, 2024. On November 29, 2023, Cascade issued $100.0 million of senior notes under a note purchase agreement with a maturity date of November 30, 2033 and an interest rate of 6.39 percent. The agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments. Intermountain Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments. On January 20, 2023, Intermountain entered into a $125.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of January 19, 2024. In March, April and May 2023, Intermountain paid down $20.0 million, $30.0 million and $30.0 million, respectively, of the outstanding balance, with the final $45.0 million repayment made on January 19, 2024. On November 29, 2023, Intermountain issued $25.0 million of senior notes under a note purchase agreement with a maturity date of November 30, 2033 and an interest rate of 6.19 percent. The agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments. Centennial On March 18, 2022, Centennial entered into a $100.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of March 17, 2023. On March 17, 2023, Centennial amended the agreement to extend the maturity date to September 15, 2023. On May 31, 2023, Centennial repaid the full balance outstanding under the term loan agreement. On December 19, 2022, Centennial entered into a $135.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of December 18, 2023. On May 31, 2023, Centennial repaid the full balance outstanding under the term loan agreement. 56 MDU Resources Group, Inc. Form 10-K Index Part II On June 9, 2023, Centennial repaid the full balances outstanding on all its long-term senior note debt, which aggregated $455.0 million, as previously discussed. MDU Resources Group, Inc. On May 1, 2023, the Company entered into a $75.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of November 1, 2023. On May 31, 2023, the Company repaid the full balance outstanding under the term loan agreement. On May 31, 2023, the Company entered into a $150.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 29, 2024. At December 31, 2023, the Company had no amount outstanding. The agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments. On May 31, 2023, the Company entered into a $200.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2028. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The credit agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments. On May 31, 2023, the Company entered into a $375.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2025. On November 15, 2023, the Company paid down $185.0 million of this term loan. The term loan agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loan and investments. As discussed in Note 3, the Company retained 10 percent of the shares of Knife River with the intent to monetize its investment and provide proceeds to the Company. On November 6, 2023, the Company entered into a $310.0 million term loan agreement which was used to facilitate the tax-free debt for equity exchange. This term loan was repaid through a noncash exchange of the Company's shares in Knife River for $293.2 million and the remaining balance of this term loan was repaid in cash on November 10, 2023. Equity Resources In August 2020, the Company amended the Distribution Agreement dated February 22, 2019, with J.P. Morgan Securities LLC and MUFG Securities Americas Inc., as sales agents. This agreement, as amended, allows the offering, issuance and sale of up to 6.4 million shares of the Company's common stock in connection with an “at-the-market” offering. On August 10, 2023, the Company terminated the distribution agreement. Prior to the termination, the Company had capacity to issue up to 3.6 million additional shares of common stock under the "at-the-market" offering program. The Company was not subject to any termination penalties related to the termination of the distribution agreement. The Company had no issuances of shares under the "at-the-market" offering program in 2023 or 2022. Dividend restrictions For information on the Company's dividends and dividend restrictions, see Item 8 - Note 13. Material cash requirements For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Item 8 - Notes 10, 11 and 22. At December 31, 2023, the Company's material cash requirements under these obligations were as follows: Less than 1 year 1-3 years 3-5 years More than 5 years Total (In millions) Short-term debt $ 95.0 $ — $ — $ — $ 95.0 Long-term debt maturities* 61.3 488.4 286.7 1,468.2 2,304.6 Estimated interest payments** 112.3 192.3 156.3 833.8 1,294.7 Operating leases 25.9 28.7 10.4 25.7 90.7 Purchase commitments 674.9 466.7 244.5 670.3 2,056.4 $ 969.4 $ 1,176.1 $ 697.9 $ 2,998.0 $ 5,841.4 * Unamortized debt issuance costs and discount are excluded from the table. ** Represents the estimated interest payments associated with the Company's long-term debt outstanding at December 31, 2023, assuming current interest rates and consistent amounts outstanding until their respective maturity dates over the periods indicated in the table above. 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. At December 31, 2023, the current portion of asset retirement obligations was $784,000 and was included in other accrued liabilities on the Consolidated Balance Sheets. MDU Resources Group, Inc. Form 10-K 57 Index Part II 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. At December 31, 2023, the Company had total liabilities of $385.2 million related to asset retirement obligations that are excluded from the table above. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. For more information, see Item 8 - Note 12. Not reflected in the previous table are $2.3 million in uncertain tax positions at December 31, 2023. The Company's minimum funding requirements for its defined benefit pension plans for 2024, which are not reflected in the previous table, is $3.3 million. For information on potential contributions above the funding minimum requirements, see item 8 - Note 19. The Company's MEPP contributions are based on union employee payroll, which cannot be determined in advance for future periods. The Company may also be required to make additional contributions to its MEPPs as a result of their funded status. For more information, see Item 1A - Risk Factors and Item 8 - Note 19. New Accounting Standards For information regarding new accounting standards, see Item 8 - Note 2, which is incorporated herein by reference. Critical Accounting Estimates The Company has prepared its financial statements in conformity with GAAP. The preparation of its financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities, at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Management reviews these estimates and assumptions based on historical experience, changes in business conditions and other relevant factors believed to be reasonable under the circumstances. Critical accounting estimates are defined as estimates that require management to make assumptions about matters that are uncertain at the time the estimate was made and changes in the estimates could have a material impact on the Company's financial position or results of operations. The Company's critical accounting estimates are subject to judgments and uncertainties that affect the application of its significant accounting policies discussed in Item 8 - Note 2. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, the Company's financial position or results of operations may be materially different when reported under different conditions or when using different assumptions in the application of the following critical accounting estimates. Goodwill The Company performs its goodwill impairment testing annually in the fourth quarter. In addition, the test is performed on an interim basis whenever events or circumstances indicate that the carrying amount of goodwill may not be recoverable. Examples of such events or circumstances may include a significant adverse change in business climate, weakness in an industry in which the Company's reporting units operate or recent significant cash or operating losses with expectations that those losses will continue. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Item 8 - Note 18. Goodwill impairment, if any, is measured by comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the goodwill of the reporting unit is not impaired. If the carrying value of a reporting unit exceeds its fair value, the Company must record an impairment loss for the amount that the carrying value of the reporting unit, including goodwill, exceeds the fair value of the reporting unit. For the years ended December 31, 2023, 2022 and 2021, there were no impairment losses recorded. At October 31, 2023, the fair value substantially exceeded the carrying value at the Company's construction services reporting unit. The Company's annual impairment testing indicated the natural gas distribution reporting unit's fair value is not substantially in excess of its carrying value ("cushion"). Based on the Company's assessment, the estimated fair value of the natural gas distribution reporting unit exceeded its carrying value, which includes $345.7 million of goodwill, by approximately 4 percent as of October 31, 2023. The decrease in the natural gas distribution reporting unit's cushion from the prior year was primarily attributable to the risk adjusted cost of capital increasing from 6.4 percent in 2022 to 6.7 percent 2023, which directly correlates with the treasury rates at the date of the test. The natural gas distribution reporting unit is at risk of future impairment if projected operating results are not met or other inputs into the fair value measurement model change. Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, long-term growth rates, amount and timing of estimated capital expenditures, inflation rates, risk adjusted cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information. 58 MDU Resources Group, Inc. Form 10-K Index Part II The Company uses a discounted cash flow methodology for its income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the risk adjusted cost of capital at each reporting unit. The risk adjusted cost of capital varies by reporting unit and was in the range of 6 percent to 10 percent in 2023, 6 percent to 9 percent for 2022 and 5 percent to 8 percent for 2021 from its continuing reporting units. Under the market approach, the Company estimates fair value using various multiples derived from enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company also uses a rate base multiple, based on recent comparable industry transactions, at its natural gas distribution reporting unit. With the exception of the rate base trading multiple, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company used a 20 percent control premium in 2023 and 2022 and a 15 percent control premium in 2021. The Company uses significant judgment in estimating its five-year forecast. The assumptions underlying cash flow projections are in sync as applicable with the Company's strategy and assumptions. Future projections are heavily correlated with the current year results of operations. Future results of operations may vary due to economic and financial impacts. The long-term growth rates are developed by management based on industry data, management's knowledge of the industry and management's strategic plans. The long-term growth rate varies by reporting unit. Construction services long-term growth rate was 3.0 percent in 2023, 2022 and 2021. Natural gas distribution's long-term growth rate was 3.0 percent, 2.85 percent and 1.6 percent in 2023, 2022 and 2021, respectively. Regulatory accounting The Company is subject to rate regulation by state public service commissions and/or the FERC. Regulatory assets generally represent incurred or accrued costs that have been deferred and are expected to be recovered in rates charged to customers. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. Management continually assesses the likelihood of recovery in future rates of incurred costs and refunds to customers associated with regulatory assets and liabilities. Decisions made by the various regulatory agencies can directly impact the amount and timing of these items. Therefore, expected recovery or refund of these deferred items generally is based on specific ratemaking decisions or precedent for each item. If future recovery of costs is no longer probable, the Company would be required to include those costs in the statement of income or accumulated other comprehensive loss in the period in which it is no longer deemed probable. The Company believes that the accounting subject to rate regulation remains appropriate and its regulatory assets are probable of recovery in current rates or in future rate proceedings. At December 31, 2023 and 2022, the Company's regulatory assets were $619.6 million and $494.8 million, respectively, and regulatory liabilities were $591.8 million and $474.9 million, respectively. At December 31, 2023 and 2022, regulatory assets in recovery were $496.1 million and $427.8 million, respectively, and regulatory assets not in recovery were $123.5 million and $67.0 million, respectively. Revenue recognition Revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The recognition of revenue requires the Company to make estimates and assumptions that affect the reported amounts of revenue. The accuracy of revenues reported on the Consolidated Financial Statements depends on, among other things, management's estimates of total costs to complete projects because the Company uses the cost-to-cost measure of progress on construction contracts for revenue recognition. To determine the proper revenue recognition method for contracts, the Company evaluates whether two or more contracts should be combined and accounted for as one single contract and whether the combined or single contract should be accounted for as more than one performance obligation. This evaluation requires significant judgment and the decision to combine a group of contracts or separate the combined or single contract into multiple performance obligations could change the amount of revenue and profit recorded in a given period. For most contracts, the customer contracts with the Company to provide a significant service of integrating a complex set of tasks and components into a single project. Hence, the Company's contracts are generally accounted for as one performance obligation. The Company recognizes construction contract revenue over time using an input method based on the cost-to-cost measure of progress for contracts because it best depicts the transfer of assets to the customer which occurs as the Company incurs costs on the contract. Under the cost-to-cost measure of progress, the costs incurred are compared with total estimated costs of a performance obligation. Revenues are recorded proportionately to the costs incurred. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs. Since contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners. Changes in estimates could have a material effect on the Company's results of operations, financial position and cash flows. For the years ended December 31, 2023 and 2022, the Company's total construction contract revenue was $2.8 billion and $2.6 billion, respectively. MDU Resources Group, Inc. Form 10-K 59 Index Part II Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates. As a project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions surrounding the job become known. If a loss is anticipated on a contract, the loss is immediately recognized. Contracts are often modified to account for changes in contract specifications and requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Generally, contract modifications are for goods or services that are not distinct from the existing contract due to the significant integration of services provided in the context of the contract and are accounted for as if they were part of that existing contract. The effect of a contract modification on the transaction price and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue on a cumulative catch-up basis. The Company's construction contracts generally contain variable consideration including liquidated damages, performance bonuses or incentives, claims, unpriced change orders and penalties or index pricing. The variable amounts usually arise upon achievement of certain performance metrics or change in project scope. The Company estimates the amount of revenue to be recognized on variable consideration using one of the two prescribed estimation methods, the expected value method or the most likely amount method, depending on which method best predicts the most likely amount of consideration the Company expects to be entitled to or expects to incur. Assumptions as to the occurrence of future events and the likelihood and amount of variable consideration are made during the contract performance period. Estimates of variable consideration and assessment of anticipated performance and all information (historical, current and forecasted) that is reasonably available to management. The Company only includes variable consideration in the estimated transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur or when the uncertainty associated with the variable consideration is resolved. Changes in circumstances could impact management's estimates made in determining the value of variable consideration recorded. When determining if the variable consideration is constrained, the Company considers if factors exist that could increase the likelihood of the magnitude of a potential reversal of revenue. The Company updates its estimate of the transaction price each reporting period and the effect of variable consideration on the transaction price is recognized as an adjustment to revenue on a cumulative catch-up basis. The Company received notification from a customer on a large project with a contract that was billed on a time and materials basis with no stated maximum price, that it is withholding payment of approximately $31.0 million on remaining outstanding billings, including retention. The Company believes it has substantial defenses against these claims based upon the terms of the contract and the Company's belief that it has performed under the terms of the contract. The Company believes collection of the remaining outstanding billings, including retention is probable and, as a result, the Company has recognized the revenue from this project in its results. However, there is uncertainty surrounding this matter, including the potential long-term nature of dispute resolution, the Company filing a lien on the property and the broad range of possible consideration amounts as a result of negotiations and potential litigation to resolve the dispute. The Company believes its estimates surrounding the cost-to-cost method are reasonable based on the information that is known when the estimates are made. The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes available for each job. Pension and other postretirement benefits The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions. The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term return on plan assets, actuarially determined mortality data and health care cost trend rates. In selecting the expected long-term return on plan assets, which is considered to be one of the key variables in determining benefit expense or income, the Company considers historical returns, current market conditions, the mix of investments and expected future market trends, including changes in interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate. In selecting the discount rate, the Company matches forecasted future cash flows of the pension and postretirement plans to a yield curve which consists of a hypothetical portfolio of high-quality corporate bonds with varying maturity dates, as well as other factors, as a basis. The Company's pension and other postretirement benefit plan assets are primarily made up of equity and fixed-income investments. Fluctuations in actual equity and bond market returns, as well as changes in general interest rates, may result in increased or decreased pension and other postretirement benefit costs in the future. Health care cost trend rates are determined by historical and future trends. 60 MDU Resources Group, Inc. Form 10-K Index Part II The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is known when the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets and health care cost trend rates. A 50 basis point change in the assumed discount rate and the expected long-term return on plan assets would have had the following effects at December 31, 2023: Pension Benefits Other Postretirement Benefits 50 Basis Point Increase 50 Basis Point Decrease 50 Basis Point Increase 50 Basis Point Decrease Discount rate (In millions) Projected benefit obligation as of December 31, 2023 $ (12.0) $ 13.0 $ (1.7) $ 1.9 Net periodic benefit cost (credit) for 2024 $ .1 $ (.1) $ (.2) $ .2 Expected long-term return on plan assets Net periodic benefit cost (credit) for 2024 $ (1.4) $ 1.4 $ (.4) $ .4 A 100 basis point change in the assumed health care cost trend rates would have had the following effects at December 31, 2023: 100 Basis Point Increase 100 Basis Point Decrease (In millions) Service and interest cost components for 2024 $ — $ — Postretirement benefit obligation as of December 31, 2023 $ 0.4 $ (0.4) The Company plans to continue to use its current methodologies to determine plan costs. For more information on the assumptions used in determining plan costs, see Item 8 - Note 19. Income taxes The Company is required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to estimate the Company's obligation to taxing authorities. These tax obligations include income, real estate, franchise and sales/use taxes. Judgments related to income taxes require the recognition in the Company's financial statements that a tax position is more-likely-than-not to be sustained on audit. Judgment and estimation is required in developing the provision for income taxes and the reporting of tax-related assets and liabilities and, if necessary, any valuation allowances. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income tax could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows and tax-related assets and liabilities. In addition, the effective tax rate may be affected by other changes including the allocation of property, payroll and revenues between states. The Company assesses the deferred tax assets for recoverability taking into consideration historical and anticipated earnings levels; the reversal of other existing temporary differences; available net operating losses and tax carryforwards; and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, a valuation allowance against the deferred tax assets. As facts and circumstances change, adjustment to the valuation allowance may be required.