EDGAR 10-K Filing

Company CIK: 67716
Filing Year: 2024
Filename: 67716_10-K_2024_0000067716-24-000017.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
General
The Company is a regulated energy delivery and construction services business. Its principal executive offices are located at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.
Montana-Dakota was incorporated under the state laws of Delaware in 1924. The Company was incorporated under the state laws of Delaware in 2018. Upon the completion of the Holding Company Reorganization, Montana-Dakota became a subsidiary of the Company. The Company's mission is to deliver superior value to stakeholders by providing essential infrastructure and services to America.
The Company's strategy is to deliver superior value and achieve industry-leading performance by becoming a pure-play regulated energy delivery company, while pursuing organic growth opportunities. Through its regulated energy delivery businesses, the Company generates, transmits and distributes electricity and provides natural gas distribution, transportation and storage services. These businesses are regulated by state public service commissions and/or the FERC. The construction services business provides construction services through its electrical and mechanical and transmission and distribution specialty contracting services.
As part of the Company's continual review of its business, the Company announced strategic initiatives that are expected to enhance its value. On May 31, 2023, the Company executed the separation of Knife River, the construction materials and contracting business, from the Company, resulting in Knife River becoming an independent, publicly traded company. On November 2, 2023, the Company announced that its board of directors approved a plan to spinoff its wholly-owned construction services business, MDU Construction Services. The proposed separation of MDU Construction Services is planned as a tax-free spinoff transaction to the Company’s stockholders for U.S. federal income tax purposes. Completion of the proposed MDU Construction Services' separation will be subject to, among other things, the effectiveness of a registration statement on Form 10 with the SEC, final approval from the Company’s board of directors, receipt of one or more tax opinions and a private letter ruling from the IRS, and other customary conditions. The Company may, at any time and for any reason until the proposed transaction is complete, abandon the separation or modify or change its terms. The proposed separation is expected to be complete in late 2024, but there can be no assurance regarding the ultimate timing of the separation or that the separation will ultimately occur.
As of December 31, 2023, the Company was organized into four reportable business segments. These business segments include: electric, natural gas distribution, pipeline, and construction services. The Company's business segments are determined based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these segments is defined based on the reporting and review process used by the Company's chief executive officer.
MDU Resources Group, Inc. Form 10-K 7
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Part I
The Company, through its wholly owned subsidiary, MDU Energy Capital, owns Montana-Dakota, Cascade and Intermountain. The electric segment is comprised of Montana-Dakota while the natural gas distribution segment is comprised of Montana-Dakota, Cascade and Intermountain.
The Company, through its wholly owned subsidiary, Centennial, owns WBI Energy, MDU Construction Services and Centennial Capital. WBI Energy is the pipeline segment, MDU Construction Services is the construction services segment, and Centennial Capital is reflected in the Other category.
The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth in Item 7 - MD&A and Item 8 - Note 18.
The Company's material properties, which are of varying ages and are of different construction types, are generally in good condition, are well maintained and are generally suitable and adequate for the purposes for which they are used.
Human Capital Management The Company continues to focus on building a strong workforce. This means building a strong team of employees with a focus on safety and a commitment to diversity, equity and inclusion. The Company's team was located in 27 states as of December 31, 2023. The number of employees fluctuates during the year due to the seasonality and the number and size of construction projects. During 2023, the number of employees, excluding the former construction materials and contracting business, which was spun off on May 31, 2023, peaked in the first quarter at just over 11,100. Employees as of December 31, 2023, were as follows:
Many of the Company's employees are represented by collective-bargaining agreements and the Company is committed to establishing constructive dialogue with this representation and bargain in good faith. The majority of the collective-bargaining agreements contain provisions that prohibit work stoppages or strikes and provide dispute resolution through binding arbitration in the event of an extended disagreement.
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The following information is as of December 31, 2023.
Company Collective-bargaining agreement Number of employees represented Agreement status
Montana-Dakota IBEW 293 Effective through April 30, 2024
Intermountain UA 135 Effective through March 31, 2027 with 2 agreements in negotiations
Cascade ICWU 189 Effective through March 31, 2024
WBI Energy Transmission IBEW 68 Effective through April 30, 2024
MDU Construction Services 102 various agreements
5,704 1 agreement in negotiations
Total 6,389
Diversity, Equity and Inclusion The Company is committed to an inclusive environment that respects the differences and embraces the strengths of its diverse employees. Essential to the Company's success is its ability to attract, retain and engage the best people from a broad range of backgrounds and build an inclusive culture where all employees feel valued and contribute their best. To aid in the Company's commitment to an inclusive environment, each business segment has a diversity officer who serves as a conduit for diversity-related issues and provides a voice to all employees. The Company requires employees to participate in its Leading with Integrity training which provides training on the Company's code of conduct and additional courses focusing on diversity, effective leadership, equal employment opportunity, workplace harassment, respect and unconscious bias.
The Company has three strategic goals related to diversity:
•Enhance collaboration efforts through cooperation and sharing of best practices to create new ways of meeting employee, customer and stockholder needs.
•Maintain a culture of integrity, respect and safety by ensuring employees understand these essential values which are part of the Company's vision statement.
•Increase productivity and profitability through the creation of a work environment which values all perspectives and methods of accomplishing work.
The Company also promotes its strategic diversity goals through the following special recognition awards:
In March 2022, the chief executive officer of the Company joined more than 2,000 chief executive officers in signing the CEO Action for Diversity and Inclusion Pledge. Through this collaboration with other companies, the Company furthers its commitment to a diverse and inclusive environment that respects the differences and embraces the strengths of its employees to further its corporate vision.
Building People Building a strong workforce begins with employee recruitment. The Company hires and trains employees to have the skills, abilities and motivation to achieve the results needed for their jobs. Each job is important and part of a coordinated team effort to accomplish the organization's objectives. The Company uses a variety of means to recruit new employees for open positions including posting on the Company's website at www.jobs.mdu.com, which is not incorporated by reference herein. Other sources for employee recruitment include employee referrals, union workforce, direct recruitment, advertising, social media, career fairs, partnerships with colleges and technical schools, job service organizations and associations connected with a variety of professions. The Company also uses internship programs to introduce individuals to the Company's business operations and provide a possible source of future employees.
MDU Resources Group, Inc. Form 10-K 9
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Part I
Building a strong workforce also requires developing employees in their current positions and for future advancement. The Company provides opportunities for advancement through job mobility, succession planning and promotions both within and between business segments. The Company provides employees the opportunity to further develop and grow through various forms of training, mentorship programs and internship programs, among other things.
To attract and retain employees, the Company offers:
The Company conducts employee surveys to hear and gauge employee opinions on issues such as fairness, camaraderie and pride in the workplace. Survey responses are compiled and evaluated at various levels throughout the Company to develop action plans to address areas of concern raised by employees.
Safety Safety is a corporate value and top priority of the Company. The Company is committed to safety and health in the workplace. To ensure safe work environments, the Company provides training, resources and appropriate follow-up on any unsafe conditions or actions. To facilitate a strong safety culture, the Company established its Safety Leadership Council. In addition to the Safety Leadership Council, the Company has policies and training that support safety in the workplace including training on safety matters through classroom and toolbox meetings on job sites. The Company utilizes safety compliance in the evaluation of employees, which includes management, and recognizes employee safety through safety award programs. Accident and safety statistical information is gathered for each of the business segments and regularly reported to management and the board of directors.
Environmental Matters The Company believes it has a responsibility to use natural resources efficiently and attempt to minimize the environmental impact of its activities. The Company produces GHG emissions primarily from its fossil fuel electric-generating facilities, as well as from natural gas pipeline and storage systems, and operations of equipment and fleet vehicles. The Company has developed renewable generation with lower or no GHG emissions. Governmental legislation and regulatory initiatives regarding environmental and energy policy are continuously evolving and could negatively impact the Company's operations and financial results. As legislation and regulation are finalized, the impact of these measures can be assessed. The Company will continue to monitor legislative and regulatory activity related to environmental and energy policy initiatives. In addition, for a discussion of the Company's risks related to environmental laws and regulations, see Item 1A - Risk Factors.
The Company maintains an executive management Sustainability Committee that supports the execution of, and makes recommendations to advance, the Company's environmental and sustainability strategy. For more information on the Company's sustainability goals, programs and performance, see the Company's Sustainability Report on its website, which is not incorporated by reference herein.
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Governmental Matters The operations of the Company and certain of its subsidiaries are subject to laws and regulations relating to air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal and state health and safety regulations; and state hazard communication standards.
The Company strives to be in substantial compliance with applicable regulations, except as to what may be ultimately determined with regard to items discussed in Environmental matters in Item 8 - Note 22. There are no pending CERCLA actions for any of the Company's material properties. However, the Company is involved in certain claims relating to the Bremerton Gasworks Superfund Site. For more information on the Company's environmental matters, see Item 8 - Note 22 and Item 7 - MD&A - Business Section Financial and Operating Data.
Technology The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information technology systems and network infrastructure. These systems may be vulnerable to failures or unauthorized access. The Company has policies, procedures and processes designed to strengthen and protect these systems, which include the Company’s enterprise information technology and operation technology groups continually evaluating new tools and techniques to reduce the risk and potential impacts of a cyber breach.
For a discussion of the Company's risks related to cybersecurity, see Item 1A - Risk Factors. For more information on the Company's approach to cybersecurity, see Item 1C - Cybersecurity.
Available Information This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's website as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the SEC. The Company's website address is www.mdu.com. The information available on the Company's website is not part of this annual report on Form 10-K. The SEC also maintains a website where the Company's filings can be obtained free of charge at www.SEC.gov.
Electric
General The Company's electric segment is operated through its wholly owned subsidiary, Montana-Dakota. Montana-Dakota provides electric service at retail, serving residential, commercial, industrial and municipal customers in 185 communities and adjacent rural areas.
The material properties owned by Montana-Dakota for use in its electric operations include interests in 13 electric generating units at 11 facilities and two small portable diesel generators, as further described under System Supply, System Demand and Competition, approximately 3,400 and 4,800 miles of transmission and distribution lines, respectively, and 82 transmission and 298 distribution substations. Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. At December 31, 2023, Montana-Dakota's net electric plant investment was $1.7 billion and its rate base was $1.4 billion.
Retail electric rates, service, accounting and certain securities issuances are subject to regulation by the MTPSC, NDPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota are also subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of certain securities, accounting, cybersecurity and other matters.
Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its interconnected system. MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from that market.
MDU Resources Group, Inc. Form 10-K 11
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The retail customers served and respective revenues by class for the electric business were as follows:
2023 2022 2021
Customers
Served Revenues Customers
Served Revenues Customers
Served Revenues
(Dollars in thousands)
Residential 119,700 $ 134,054 119,398 $ 135,412 119,113 $ 123,043
Commercial 23,573 164,142 23,327 142,722 23,149 133,336
Industrial 228 42,340 230 42,937 231 40,477
Other 1,607 7,075 1,606 7,335 1,610 6,754
145,108 $ 347,611 144,561 $ 328,406 144,103 $ 303,610
Other electric revenues, which are largely transmission-related revenues, for Montana-Dakota were $53.6 million, $48.7 million and $46.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.
The percentage of electric retail revenues by jurisdiction was as follows:
2023 2022 2021
North Dakota 66 % 65 % 64 %
Montana 20 % 21 % 22 %
Wyoming 9 % 9 % 9 %
South Dakota 5 % 5 % 5 %
System Supply, System Demand and Competition Through an interconnected electric system, Montana-Dakota serves markets in portions of North Dakota, Montana and South Dakota. These markets are highly seasonal and sales volumes depend largely on the weather. Additionally, the average customer consumption has tended to decline due to increases in energy efficient lighting and appliances being installed. In mid-2023 a data center began operating in the Company's service territory which led to an increase in sales volumes. As of December 31, 2023, the interconnected system consisted of 12 electric generating units at 10 facilities and two small portable diesel generators. Additional details are included in the table that follows. For 2023, Montana-Dakota's total ZRCs, including its firm purchase power contracts, were 516.1. Montana-Dakota's planning reserve margin requirement within MISO was 516.1 ZRCs for 2023. The maximum electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was 746,924 kW in July 2023. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to occur during the summer. Additional energy is purchased as needed, or in lieu of generation if more economical, from the MISO market. In 2023, Montana-Dakota purchased approximately 59 percent of its net kWh needs for its interconnected system through the MISO market.
Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 69,688 kW in August 2022. Montana-Dakota has a power supply contract with Black Hills Power, Inc. to purchase up to 49,000 kW of capacity annually through December 31, 2028. Wygen III also serves a portion of the needs of Montana-Dakota's Sheridan-area customers.
Approximately 35 percent of the electricity delivered to customers from Montana-Dakota's owned generation in 2023 was from renewable resources. Although Montana-Dakota's generation resource capacity has increased to serve the needs of its customers, the carbon dioxide emission intensity of its electric generation resource fleet has been reduced by approximately 38 percent since 2005 through the addition of renewable generation and with the retirement of aging coal-fired electric generating units, as further discussed below.
The Company ceased operations of Lewis & Clark Station in Sidney, Montana, in March 2021 and decommissioning was completed in October 2022. In February 2022, the Company ceased operations of Units 1 and 2 at Heskett Station near Mandan, North Dakota, and decommissioning was completed in December 2023. In addition, in May 2022 Montana-Dakota 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 with an in service date expected in the second quarter of 2024, assuming no further action is needed based on the conclusion of the ongoing root cause analysis, or other unexpected delays.
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The following table sets forth details applicable to the Company's electric generating stations:
Generating Station Type Fuel Nameplate Rating (kW) at December 31, 2023
2023 ZRCs (a) 2023 Net Generation (kWh in thousands)
Interconnected System:
North Dakota:
Coyote (b) Steam Coal 103,647 102.6 650,039
Heskett Combustion turbine Natural gas 89,038 85.9 29,339
Glen Ullin Renewable Heat recovery 7,500 1.8 38,008
Cedar Hills Renewable Wind 19,500 4.5 52,440
Thunder Spirit Renewable Wind 155,500 34.4 488,369
South Dakota:
Big Stone (b) Steam Coal 94,111 111.6 353,842
Montana:
Lewis & Clark Reciprocating internal combustion engine Natural gas 18,700 15.4 20,889
Glendive Combustion turbine Natural gas / diesel 75,522 49.6 2,727
Miles City Combustion turbine Natural gas / diesel 23,150 17.3 312
Diamond Willow Renewable Wind 30,000 5.8 82,375
Portable Units (2) Reciprocating internal combustion engine Diesel 3,650 3.7 12
620,318 432.6 1,718,352
Sheridan System:
Wyoming:
Wygen III (b) Steam Coal 28,000 N/A 197,522
648,318 432.6 1,915,874
(a)Interconnected system only. MISO requires generators to obtain their seasonal capability through the GVTC. The GVTC is then converted to ZRCs by applying each generator's forced outage factor against its GVTC. Wind generator's ZRCs are calculated based on a wind capacity study performed annually by MISO. ZRCs are used to meet supply obligations within MISO.
(b)Reflects Montana-Dakota's ownership interest.
The owners of Coyote Station, including Montana-Dakota, have a contract with Coyote Creek for coal supply to the Coyote Station that expires December 2040. Montana-Dakota estimates the Coyote Station coal supply agreement to be approximately 1.5 million tons per contract year. For more information, see Item 8 - Note 22.
The owners of Big Stone Station, including Montana-Dakota, have a coal supply agreement with Peabody COALSALES, LLC to meet all of the Big Stone Station's fuel requirements through 2024. Montana-Dakota estimates the Big Stone Station coal supply agreement to be approximately 1.5 million tons per contract year.
Montana-Dakota has a coal supply agreement with Wyodak Resources Development Corp., to supply the coal requirements of Wygen III at contracted pricing through June 1, 2060. Montana-Dakota estimates the maximum annual coal consumption of the facility to be approximately 585,000 tons.
Montana-Dakota has entered into four purchase power agreements to purchase capacity and energy between the retirement of the Lewis & Clark Station and Heskett Station Units 1 and 2 and the timing of completion of the new Heskett Unit 4. As part of the four purchase power agreements, Montana-Dakota purchased additional MISO replacement capacity associated with the delay in commercial operation of Heskett Unit 4. Montana-Dakota also purchased additional capacity and energy to cover forecasted capacity deficits through May 2026.
Montana-Dakota expects that it has secured adequate capacity available through existing baseload generating stations, renewable generation, turbine peaking stations, demand reduction programs and firm contracts to meet the peak customer demand requirements of its customers through 2030. Future capacity needs are expected to be met by constructing new generation resources or acquiring additional capacity through power purchase contracts or the MISO capacity auction.
Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.
Montana-Dakota is subject to competition resulting from customer demands, technological advances and other factors in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas.
Montana-Dakota is not dependent on any single customer or group of customers for sales of its products and services, where the loss of which would have a material adverse effect on its business.
MDU Resources Group, Inc. Form 10-K 13
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Regulatory Matters and Revenues Subject to Refund In North Dakota, Montana, South Dakota and Wyoming, there are various recurring regulatory mechanisms with annual true-ups that can impact Montana-Dakota's results of operations, which also reflect monthly increases or decreases in electric fuel and purchased power costs (including demand charges). Montana-Dakota is deferring those electric fuel and purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. Examples of these recurring mechanisms include: monthly Fuel and Purchased Power Tracking Adjustments, a fuel adjustment clause, and an annual Electric Power Supply Cost Adjustment. Such mechanisms generally provide that these deferred fuel and purchased power costs are recoverable or refundable through rate adjustments which are filed annually. Montana-Dakota's results of operations reflect 95 percent of the increases or decreases from the base purchased power costs and also reflect 85 percent of the increases or decreases from the base coal price, which is also recovered through the Electric Power Supply Cost Adjustment in Wyoming. For more information on regulatory assets and liabilities, see Item 8 - Note 6.
All of Montana-Dakota's wind resources pertaining to electric operations in North Dakota are included in a renewable resource cost adjustment rider, including the North Dakota investment in Thunder Spirit. Montana-Dakota also has a transmission tracker in North Dakota to recover transmission costs associated with MISO and SPP, along with certain of the transmission investments not recovered through retail rates. The tracking mechanism has an annual true-up.
In South Dakota, Montana-Dakota recovers the South Dakota investment in Thunder Spirit through an Infrastructure Rider tracking mechanism that is subject to an annual true-up. Montana-Dakota also has in place in South Dakota a transmission tracker to recover transmission costs associated with MISO and SPP, along with certain of the transmission investments not recovered through retail rates. This tracking mechanism also has an annual true-up.
In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, its allocated share of Montana property-related taxes assessed to electric operations on an after-tax basis.
For more information on regulatory matters, see Item 8 - Note 21.
Environmental Matters Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal and state health and safety regulations; and state hazard communication standards. The electric operations strive to be in compliance with these regulations.
Montana-Dakota's electric generating facilities have Title V Operating Permits, under the federal Clean Air Act, issued by the states in which they operate. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration. The WYDEQ determined all units at the Neil Simpson Complex, where Wygen III is situated, are to be included within a combined Title V Operating Permit which was submitted in June 2022. Wygen III is currently allowed to operate under the facility's construction permit until the Title V Operating Permit is issued. The Title V Operating Permit renewal application for Big Stone Station was submitted timely in October 2021 to the South Dakota Department of Agriculture & Natural Resources with the permit issuance date not specified at this time.
State water discharge permits issued under the requirements of the federal Clean Water Act are maintained for power production facilities on the Missouri river. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army Corps permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct and do not require renewal. Other permit terms vary and the permits are renewed as necessary.
Montana-Dakota's electric operations are very small-quantity generators of hazardous waste and subject only to minimum regulation under the RCRA and when required notifies federal and state agencies of episodic generation events. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.
Montana-Dakota incurred approximately $2.9 million of capital expenditures in 2023 related to the closure of coal ash management units at Lewis & Clark Station and Heskett Station and to maintain air emissions compliance at its co-owned electric generating facilities. Environmental related capital expenditures are estimated to be $870,000, $1.4 million and $1.2 million in 2024, 2025 and 2026, respectively, for the closure of coal ash management units at Lewis & Clark Station and Heskett Station and to maintain air emissions compliance at its co-owned electric generating facilities and does not expect to incur any material capital expenditures in 2024, 2025 and 2026 for compliance with current environmental laws and regulations. Montana-Dakota's capital and operational expenditures could also be affected by future environmental requirements, such as existing and proposed emissions reduction plans from the EPA. For more information, see Item 1A - Risk Factors and Item 7 - MD&A - Business Section Financial and Operating Data.
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Natural Gas Distribution
General The Company's natural gas distribution segment is operated through its wholly owned subsidiaries, consisting of operations from Montana-Dakota, Cascade and Intermountain. These companies sell natural gas at retail, serving residential, commercial and industrial customers in 338 communities and adjacent rural areas across eight states. They also provide natural gas transportation services to certain customers on the Company's systems.
These services are provided through distribution and transmission systems aggregating approximately 21,600 miles and 600 miles, respectively. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. These operations intend to seek renewal of all expiring franchises. At December 31, 2023, the natural gas distribution operations' net natural gas distribution plant investment was $2.4 billion and its rate base was $1.8 billion.
The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates, service, accounting and certain securities issuances.
The retail customers served and respective revenues by class for the natural gas distribution operations were as follows:
2023 2022 2021
Customers
Served Revenues Customers
Served Revenues Customers
Served Revenues
(Dollars in thousands)
Residential 935,235 $ 726,064 922,266 $ 715,494 905,535 $ 548,091
Commercial 112,966 441,199 111,478 450,932 110,196 330,468
Industrial 1,074 45,009 1,077 41,466 939 31,103
1,049,275 $ 1,212,272 1,034,821 $ 1,207,892 1,016,670 $ 909,662
Transportation and other revenues for the natural gas distribution operations were $75.3 million, $65.9 million and $62.3 million for the years ended December 31, 2023, 2022 and 2021, respectively.
The percentage of the natural gas distribution operations' retail sales revenues by jurisdiction was as follows:
2023 2022 2021
Idaho 33 % 28 % 27 %
Washington 28 % 26 % 29 %
North Dakota 12 % 16 % 15 %
Oregon 9 % 8 % 8 %
Montana 8 % 10 % 10 %
South Dakota 5 % 6 % 6 %
Minnesota 3 % 4 % 3 %
Wyoming 2 % 2 % 2 %
System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting principally of residential and commercial space and water heating users, in portions of Idaho, Minnesota, Montana, North Dakota, Oregon, South Dakota, Washington and Wyoming. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are mitigated in certain jurisdictions by weather normalization mechanisms discussed later in Regulatory Matters. Additionally, the average customer consumption has tended to decline as more efficient appliances and furnaces are installed and as the Company has implemented conservation programs. In addition to the residential and commercial sales, the utilities transport natural gas for larger commercial and industrial customers who purchase their own supply of natural gas.
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Competition resulting from customer demands, technological advances and other factors exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial loads. These rates have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain customers have bypassed the distribution systems by directly accessing transmission pipelines within close proximity. These bypasses do not have a material effect on results of operations.
The natural gas distribution operations and various distribution transportation customers obtain natural gas for their system requirements directly from producers, processors and marketers. The Company's purchased natural gas is supplied by a portfolio of contracts specifying market-based pricing and is transported under transportation agreements with WBI Energy Transmission, Northern Border Pipeline Company, Northwest Pipeline LLC, South Dakota Intrastate Pipeline, Northern Natural Gas, Gas Transmission Northwest LLC, Northwestern Energy, Viking Gas Transmission Company, Enbridge Westcoast Energy, Inc., Ruby Pipeline LLC, Foothills Pipe Lines Ltd., NOVA Gas Transmission Ltd, TC Energy Corporation, Northwest Natural, Black Hills Energy and TransCanada. The natural gas distribution operations have contracts for storage services to provide gas supply during the winter heating season and to meet peak day demand with various storage providers, including WBI Energy Transmission, Dominion Energy Questar Pipeline, LLC, Northwest Pipeline LLC and Northern Natural Gas. In addition, certain of the operations have entered into natural gas supply management agreements with various parties. Demand for natural gas, which is a widely traded commodity, has historically been sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The Company believes supplies are adequate for the natural gas distribution operations to meet its system natural gas requirements for the next decade. This belief is based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available through its suppliers and pipeline service providers.
Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current tariffs allow for recovery or refunds of under- or over-recovered gas costs through rate adjustments which are filed annually.
In North Dakota and South Dakota, Montana-Dakota's natural gas tariffs contain weather normalization mechanisms applicable to certain firm customers that adjust the distribution delivery charges to reflect weather fluctuations during the November 1 through May 1 billing periods.
In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, its allocated share of Montana property-related taxes assessed to natural gas operations on an after-tax basis.
In Minnesota and Washington, Great Plains and Cascade recover qualifying capital investments related to the safety and integrity of the pipeline systems through cost recovery tracking mechanisms.
In Oregon, Cascade has a decoupling mechanism in place approved by the OPUC until January 1, 2025, with a review to be completed by September 30, 2024. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC.
On July 7, 2016, the WUTC approved a full decoupling mechanism where Cascade is allowed recovery of an average revenue per customer regardless of actual consumption. The mechanism also includes an earnings sharing component if Cascade earns in excess of its authorized return. On September 15, 2021, the WUTC extended the effectiveness of the decoupling mechanism until the earlier of the rate effective date resulting from Cascade's next full general rate case or August 31, 2025.
On December 22, 2016, the MNPUC approved a request by Great Plains to implement a full revenue decoupling mechanism pilot project for three years. The decoupling mechanism reflects the period January 1 through December 31. The MNPUC adopted the administrative law judge's recommendation to extend the initial pilot period through the end of 2021. On May 13, 2022, Great Plains requested the continuation of the revenue decoupling mechanism. On April 13, 2023, the MNPUC denied the Company's request to extend the decoupling mechanism.
In Idaho, Intermountain has the authority to facilitate access for RNG producers to the Company's distribution system for the purpose of moving RNG to the producer's end-use customers.
For more information on regulatory matters, see Item 8 - Note 21.
Environmental Matters The natural gas distribution operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The natural gas distribution operations strive to be in compliance with these regulations.
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The Company's natural gas distribution operations are very small-quantity generators of hazardous waste, and subject only to minimum regulation under the RCRA. A Washington state rule defines Cascade as a small-quantity generator, but regulation under the rule is similar to RCRA. Certain locations of the natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Capital and operational expenditures for natural gas distribution operations could be affected in a variety of ways by potential new GHG legislation or regulation. In particular, such legislation or regulation would likely increase capital expenditures for energy efficiency and conservation programs and operational and gas supply costs associated with GHG emissions compliance. Natural gas distribution operations expect to recover the operational and capital expenditures for GHG regulatory compliance in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations. For more information, see Item 7 - MD&A - Business Section Financial and Operating Data.
The natural gas distribution operations incurred $4.1 million of capital expenditures in 2023 to construct infrastructure supporting multiple renewable natural gas facilities related to compliance with current environmental laws and regulations. Cascade and Montana-Dakota expect to incur environmental related capital expenditures of $22.6 million and $7.6 million, in 2024 and 2025, respectively. The capital expenditures are to construct infrastructure supporting multiple renewable natural gas production facilities, including the development and construction of a renewable natural gas facility at the Deschutes County Landfill near Bend, Oregon, the implementation of an advanced natural gas leak detection system and investigation of a historic manufactured gas plant site. Except as to what may be ultimately determined with regard to the issues described in the following paragraph and the items noted, the natural gas distribution operations do not expect to incur any material capital expenditures related to compliance with current environmental laws and regulations through 2026.
Montana-Dakota has ties to six historic manufactured gas plants as a successor corporation or through direct ownership of the plant. Montana-Dakota is investigating possible soil and groundwater impacts due to the operation of two of these former manufactured gas plant sites. To the extent not covered by insurance, Montana-Dakota may seek recovery in its natural gas rates charged to customers for certain investigation and remediation costs incurred for these sites. Cascade has ties to nine historic manufactured gas plants as a successor corporation or through direct ownership of the plant. Cascade is involved in the investigation and remediation of one of these manufactured gas plants in Washington. To the extent not covered by insurance, Cascade will seek recovery of investigation and remediation costs through its natural gas rates charged to customers.
See Item 8 - Note 22 for further discussion of certain manufactured gas plant sites.
Pipeline
General WBI Energy owns and operates both regulated and non-regulated businesses. The regulated business of this segment, WBI Energy Transmission, owns and operates approximately 3,800 miles of natural gas transmission and storage lines.
WBI Energy Transmission's underground storage fields provide storage services to local distribution companies, industrial customers, natural gas marketers and others, and serve to enhance system reliability. Its system is strategically located near four natural gas producing basins, making natural gas supplies available to its transportation and storage customers. The system has 14 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country and from Canada. Under the Natural Gas Act, as amended, WBI Energy Transmission is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters, and at December 31, 2023, its net plant investment was $887.8 million.
The non-regulated business of this segment provides a variety of energy-related services, including cathodic protection.
A majority of the pipeline business is transacted in the Rocky Mountain and northern Great Plains regions of the United States.
System Supply, System Demand and Competition Natural gas supplies emanate from traditional and nontraditional production activities in the region from both on-system and off-system supply sources. Incremental supply from nontraditional sources, such as the Bakken area in Montana and North Dakota, have helped offset declines in traditional regional supply sources and supports WBI Energy Transmission's transportation and storage services. In addition, off-system supply sources are available through the Company's interconnections with other pipeline systems. WBI Energy Transmission continues to look for opportunities, such as the identified growth projects discussed in Item 7 - MD&A - Pipeline Outlook, to increase transportation and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide future benefits.
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WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 350 Bcf, including 193 Bcf of working gas capacity, 83 Bcf of cushion gas and 74 Bcf of native gas. These storage facilities enable customers to purchase natural gas throughout the year and meet winter peak requirements.
WBI Energy Transmission competes with several pipelines for its customers' transportation business and at times may discount rates in an effort to retain market share; however, the strategic location of its system near four natural gas producing basins and the availability of underground storage services, along with interconnections with other pipelines, enhances its competitive position.
Although certain of WBI Energy Transmission's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure residential, commercial and industrial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.
WBI Energy Transmission transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for 2023 represented 22 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the firm transportation agreements with Montana-Dakota expire in June 2027. In addition, Montana-Dakota has a contract, expiring in July 2035, with WBI Energy Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements.
The non-regulated business of this segment competes for existing customers in the areas in which it operates. Its focus on customer service and the variety of services it offers serve to enhance its competitive position.
WBI Energy is not dependent on any single customer or group of customers for sales of its products and services, where the loss of which would have a material adverse effect on its business. WBI Energy had one third-party customer that accounted for approximately 11 percent of its 2023 revenue.
Environmental Matters The pipeline operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations.
Administration of certain provisions of federal environmental laws is delegated to the states where WBI Energy and its subsidiaries operate. Administering agencies may issue permits with varying terms and operational compliance conditions. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand, facility upgrades or modifications, and/or regulatory changes. The pipeline operations strive to be in compliance with these regulations.
Detailed environmental assessments and/or environmental impact statements as required by the National Environmental Policy Act are included in the FERC's environmental review process for both the construction and abandonment of WBI Energy Transmission's natural gas transmission pipelines, compressor stations and storage facilities.
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 pipeline operations did not incur any material capital expenditures related to compliance with current environmental laws and regulations in 2023 and do not expect to incur any material capital expenditures related to compliance with current environmental laws and regulations through 2026. Capital expenditures to meet requirements of expected or anticipated rules, including the previously discussed EPA prepublished rule in December 2023, are included in the capital expenditures for 2025 and 2026 with estimated expenditures of $4.0 million each year. For more information on the capital expenditures for this segment, see Item 7 - MD&A - Capital Expenditures.
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Construction Services
General MDU Construction Services operates in nearly every state across the country and provides a full spectrum of construction services through its electrical and mechanical and transmission and distribution specialty contracting services across the United States. These specialty contracting services are provided to utilities, manufacturing, transportation, commercial, industrial, institutional, renewable and governmental customers. Its electrical and mechanical contracting services include construction and maintenance of electrical and communication wiring and infrastructure, fire suppression systems, and mechanical piping and services. Its transmission and distribution contracting services include construction and maintenance of overhead and underground electrical, gas and communication infrastructure, as well as manufacturing and supplying transmission and distribution line construction equipment and tools.
Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather. MDU Construction Services works with the National Electrical Contractors Association, the IBEW and other trade associations on hiring and recruiting a qualified workforce.
MDU Construction Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment, such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2023, MDU Construction Services owned or leased facilities in 18 states. This space is used for offices, equipment yards, manufacturing, warehousing, storage and vehicle shops.
Competition MDU Construction Services operates in a highly competitive business environment. Most of MDU Construction Services' work is obtained on the basis of competitive bids or by negotiation of either cost-plus or fixed-price contracts. Its workforce and equipment are highly mobile, providing greater flexibility in the size and location of MDU Construction Services' market area. Competition is based primarily on price and reputation for quality, safety and reliability. The size and location of the services provided, as well as the state of the economy, are factors in the number of competitors that MDU Construction Services will encounter on any particular project. MDU Construction Services believes the diversification of the services it provides, the markets it serves in the United States and the quality and management of its workforce enable it to effectively operate in this competitive environment.
Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and subcontract work accounts for a significant portion of the work performed by MDU Construction Services and the amount of construction contracts is dependent on the level and timing of maintenance and construction programs undertaken by customers. MDU Construction Services benefits from repeat customers and strives to maintain successful long-term relationships with its customers. The mix of sales by customer class varies each year depending on available work. MDU Construction Services is not dependent on any single customer or group of customers for sales of its products and services, the loss of which would have a material adverse effect on its business. MDU Construction Services had one customer that accounted for approximately 17 percent of its revenue for 2023.
Environmental Matters MDU Construction Services' operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. MDU Construction Services strives to be in compliance with these regulations.
The nature of MDU Construction Services' operations is such that few, if any, environmental permits are required. Operational convenience supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. MDU Construction Services has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction Services' operations are conditionally exempt small-quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by MDU Construction Services.
MDU Construction Services did not incur any material capital expenditures in 2023 related to compliance with current environmental laws and regulations and does not expect to incur any material capital expenditures related to compliance with current environmental laws and regulations through 2026.
Discontinued Operations
General Discontinued operations includes Knife River's operations, as well as associated strategic initiative costs and interest on debt facilities repaid in connection with the Knife River separation. The Company completed the separation of Knife River on May 31, 2023. Discontinued operations also includes the supporting activities of Fidelity other than certain general and administrative costs and interest expense. For more information on discontinued operations, see Item 8 - Note 3.
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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents filed with the SEC. The factors and other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document. If any of the risks described below actually occur, the Company's business, prospects, financial condition or financial results could be materially harmed. The following are the most material risk factors applicable to the Company and are not necessarily listed in order of importance or probability of occurrence.
Separation Risks
The proposed separation of MDU Construction Services into an independent, publicly traded company is subject to various risks and uncertainties, and may not be completed on the terms or timeline currently contemplated, if at all.
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 proposed separation is complex, and completion of the proposed separation and the timing of its completion will be subject to a number of factors and conditions, including the readiness of the new company to operate as an independent public company, finalization of the capital structure of the new company and final approval by the board of directors, among other things. The uncertainties associated with this process, foreseen and unforeseen costs incurred, and efforts involved, may negatively affect the Company's operating results, business and the Company's relationships with employees, customers, suppliers and vendors. Unanticipated developments could delay, prevent or otherwise adversely affect the proposed separation, including, but not limited to, changes in general economic and financial market conditions and material adverse changes in business or industry conditions. There can be no assurances that the Company will be able to complete the proposed separation or that the combined value of the common stock of the two companies will be equal to or greater than what the value of the Company's common stock would have been had the proposed separation not occurred. The execution of the separation has required and may continue to require significant time and attention from the Company’s senior management and employees, which could cause disruption in business processes and adversely affect the Company's financial results and its results operations. Further the Company's employees may be distracted due to uncertainty regarding the future state of the Company. Additionally, foreseen and unforeseen costs may be incurred with the proposed separation, including fees such as advisory, accounting, tax, legal, reorganization, restructuring, and various other, some of which may be incurred regardless if the proposed separation occurs. In addition, if the separation is completed, the Company may not be able to achieve the full strategic and financial benefits that are expected to result from the separation.
If either the completed separation of Knife River or the proposed separation of MDU Construction Services, together with certain related transactions, were to fail to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, the Company and its stockholders could be subject to significant tax liabilities.
The Company completed the separation of Knife River on May 31, 2023. In connection with the completed separation of Knife River, the Company received a private letter ruling from the IRS and opinion(s) of outside counsel regarding the qualification of certain elements of the separation and distribution under Section 355(a) of the Code. Notwithstanding prior receipt of the IRS private letter ruling and opinion(s) of tax advisors, the IRS could determine that the completed distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions, or undertakings upon which the IRS private letter ruling or the opinion(s) of tax advisors were based are false or have been violated. In addition, neither the IRS private letter ruling nor opinion(s) of tax advisors will address all of the issues that are relevant to determining whether the distribution, together with certain related transactions, qualifies as a transaction that is generally tax-free for U.S. federal income tax purposes. Further, opinion(s) of tax advisors represent the judgment of such tax advisors and are not binding on the IRS or any court, and the IRS or a court may disagree with the conclusions in the opinion(s) of tax advisors. Accordingly, notwithstanding receipt by the Company of the IRS private letter ruling and the opinion(s) of tax advisors, there can be no assurance that the IRS will not assert that the distribution and/or certain related transactions do not qualify for tax-free treatment for U.S. federal income tax purposes or that a court would not sustain such a challenge. In the event the IRS were to prevail in such challenge, the Company and its stockholders could be subject to significant U.S. federal income tax liability.
Additionally, although the Company intends for the proposed separation of MDU Construction Services to be tax-free to the Company and its stockholders for U.S. federal income tax purposes, there can be no assurance that the proposed separation will qualify as such. If the distribution, together with related transactions, fails to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, in general, for U.S. federal income tax purposes, the Company would recognize taxable gain as if it had sold MDU Construction Services common stock in a taxable sale for its fair market value (unless the Company and MDU Construction Services jointly make an election under Section 336(e) of the Code with respect to the distribution, in which case, in general, (a) the Company would recognize a taxable gain as if MDU Construction Services had sold all of its assets in a taxable sale in exchange for an amount equal to the fair market value of MDU Construction Services common stock and the assumption of all of its liabilities and (b) MDU Construction Services would obtain a related step-up in the basis of its assets) and, if the distribution fails to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes under Section 355, the Company's stockholders who receive MDU Construction Services shares in the distribution would be subject to tax as if they had received a taxable distribution equal to the fair market value of such shares.
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The Company may not achieve some or all of the expected benefits of the proposed separation of MDU Construction Services, and the separation may materially and adversely affect its financial position, results of operations and cash flows.
The Company may be unable to achieve the full strategic and financial benefits expected to result from the proposed separation of MDU Construction Services, or such benefits may be delayed or not occur at all, for a variety of reasons, including, among others, that: (a) the separation will require significant time and effort from management, which may divert management’s attention from operating and growing the business; (b) following the separation and distribution, the Company may be more susceptible to stock market fluctuations and other adverse events; (c) following the separation and distribution, the Company may not be able to maintain its historical practices with respect to dividends; (d) following the separation and distribution, the Company's business will be less diversified than prior to the separation and distribution; and (e) the other actions required to separate the Company and MDU Construction Services respective businesses could disrupt their operations. If the Company fails to achieve some or all of the benefits expected to result from the separation, or if such benefits are delayed, it could have a material adverse effect on its financial position, results of operations and cash flows.
Following the proposed separation, there may be a substantial change in the Company's stockholder base and its stock price may fluctuate significantly.
Until the market has fully evaluated the Company's remaining businesses without MDU Construction Services, the price at which shares of the Company common stock trade may fluctuate more significantly than might otherwise be typical, even with other market conditions, including general volatility, held constant. There can be no assurance that the combined value of the common stock of the two companies will be equal to or greater than what the value of the Company’s common stock would have been had the proposed separation not occurred. It is possible that the Company's stockholders will sell shares of common stock for a variety of reasons. For example, such stockholders may not believe that the Company's remaining business profile or its level of market capitalization fits their investment objectives. The sale of significant amounts of the Company's common stock or the perception in the market that this will occur may lower the market price of the Company's common stock. The increased volatility of the Company's common stock price following the distribution may have a material adverse effect on its business, financial condition and results of operations.
Economic Risks
The Company is subject to government regulations that may have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party's ability to acquire the Company or impose conditions on an acquisition of or by the Company.
The Company's electric and natural gas transmission and distribution businesses are subject to comprehensive regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return and recovery of investments and costs; financing; rate structures; customer service; health care coverage and costs; taxes; franchises; recovery of fuel, purchased power and purchased natural gas costs; and construction and siting of generation and transmission facilities. These governmental regulations significantly influence the Company's operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company's results of operations and cash flows.
There can be no assurance that applicable regulatory commissions will determine that the Company's electric and natural gas transmission and distribution businesses' costs have been prudent, which could result in the disallowance of costs in setting rates for customers. Also, the regulatory process of approving rates for these businesses may not allow for timely and full recovery of the costs of providing services or a return on the Company's invested capital. Changes in regulatory requirements or operating conditions may require early retirement of certain assets. While regulation typically provides rate recovery for these retirements, there is no assurance regulators will allow full recovery of all remaining costs, which could leave stranded asset costs. Rising fuel costs could increase the risk that the utility businesses will not be able to fully recover those fuel costs from customers.
Approval from federal and state regulatory agencies would be needed for acquisition of the Company, as well as for certain acquisitions by the Company. The approval process could be lengthy and the outcome uncertain, which may deter potential acquirers from approaching the Company or impact the Company's ability to pursue acquisitions.
Economic volatility affects the Company's operations, as well as the demand for its products and services.
Unfavorable economic conditions can negatively affect the level of public and private expenditures on projects and the timing of these projects which, in turn, can negatively affect demand for the Company's products and services, primarily at the Company's construction business. The level of demand for construction services could be adversely impacted by the economic conditions in the industries the Company serves, as well as in the general economy. State and federal budget issues affect the funding available for infrastructure spending.
Economic conditions and population growth affect the electric and natural gas distribution businesses' growth in service territory, customer base and usage demand. Economic volatility in the markets served, along with economic conditions such as increased unemployment which could impact the ability of the Company's customers to make payments, could adversely affect the Company's results of operations, cash flows and asset values. Further, any material decreases in customers' energy demand, for economic or other reasons, could have an adverse impact on the Company's earnings and results of operations.
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The Company's operations involve risks that may result from catastrophic events.
The Company's operations, particularly those related to electric and natural gas transmission and distribution, include a variety of inherent hazards and operating risks, such as product leaks; explosions; mechanical failures; vandalism; fires; pandemics; social or civil unrest; protests and riots; natural disasters; cyberattacks; acts of terrorism; and acts of war. These hazards and operating risks have occurred and may reoccur in the future, which could result in loss of human life; personal injury; property damage; environmental impacts; impairment of operations; and substantial financial losses. The Company maintains insurance against some, but not all, of these risks and losses. A significant incident could also increase regulatory scrutiny and result in penalties and higher amounts of capital expenditures and operational costs. Losses not fully covered by insurance could have an adverse effect on the Company’s financial position, results of operations and cash flows.
A disruption of the regional electric transmission grid, local distribution infrastructure or interstate natural gas infrastructure could negatively impact the Company's business and reputation. There have been cyber and physical attacks within the energy industry on energy infrastructure, such as substations, and such attacks may occur in the future. Because the Company's electric and natural gas utility and pipeline systems are part of larger interconnecting systems, any attacks on the interconnected systems or the Company's infrastructure causing a disruption could result in a significant decrease in revenues and an increase in system repair costs negatively impacting the Company's financial position, results of operations and cash flows.
The Company is subject to capital market and interest rate risks.
The Company's operations, particularly its electric and natural gas transmission and distribution businesses, require significant capital investment. Consequently, the Company relies on financing sources and capital markets as sources of liquidity for capital requirements not satisfied by cash flows from operations. If the Company is not able to access capital at competitive rates, the ability to implement business plans, make capital expenditures or pursue acquisitions the Company would otherwise rely on for future growth may be adversely affected. Market disruptions may increase the cost of borrowing or adversely affect the Company's ability to access one or more financial markets. Such disruptions could include:
•A significant economic downturn.
•The financial distress of unrelated industry leaders in the same line of business.
•Deterioration in capital market conditions.
•Turmoil in the financial services industry.
•Volatility in commodity prices.
•Pandemics.
•War.
•Terrorist attacks.
•Cyberattacks.
The issuance of a substantial amount of the Company's common stock, whether issued in connection with an acquisition or otherwise, or the perception that such an issuance could occur, could have a dilutive effect on stockholders and/or may adversely affect the market price of the Company's common stock. Higher interest rates on borrowings have impacted and could further impact the Company's future operating results, as evidenced by the Company's increased interest expense in 2023 as discussed in Item 7 - MD&A.
Financial market changes could impact the Company’s pension and postretirement benefit plans and obligations.
The Company has pension and postretirement defined benefit plans for some of its current and former employees. Assumptions regarding future costs, returns on investments, interest rates and other actuarial assumptions have a significant impact on the funding requirements and expense recorded relating to these plans. Adverse changes in economic indicators, such as consumer spending, inflation data, interest rate changes, political developments and threats of terrorism, among other things, can create volatility in the financial markets. These changes could impact the assumptions and negatively affect the value of assets held in the Company's pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions for those plans.
Significant changes in prices for commodities, labor or other production and delivery inputs could negatively affect the Company's businesses.
The Company's operations are exposed to fluctuations in prices for labor, oil, raw materials and utilities. Prices are generally subject to change in response to fluctuations in supply and demand and other general economic and market conditions beyond the Company's control.
Fluctuations in oil and natural gas production, supplies and prices; fluctuations in commodity price basis differentials; political and economic conditions in oil-producing countries; actions of the Organization of Petroleum Exporting Countries; demand for oil due to economic conditions; war and other external factors impact the development of oil and natural gas supplies and the expansion and operation of natural gas pipeline systems. The Company has benefited from associated natural gas production in the Bakken, which has provided opportunities for organic growth projects. Depressed oil and natural gas prices, however, place pressure on the ability of oil exploration and production companies to meet credit requirements and can be a challenge if prices remain depressed long-term. Prolonged depressed prices for oil and natural gas could negatively affect the growth, results of operations, cash flows and asset values of the Company's electric, natural gas and pipeline businesses.
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If oil and natural gas prices increase significantly, which has occurred and may reoccur, customer demand could decline for utility, pipeline and construction services, which could impact the Company's results of operations and cash flows. While the Company has fuel clause recovery mechanisms for its utility operations in all of the states where it operates, higher utility fuel costs could also significantly impact results of operations if such costs are not recovered. Delays in the collection of utility fuel cost recoveries, as compared to expenditures for fuel purchases, could also negatively impact the Company's cash flows.
Increased labor costs, due to labor shortages, competition from other industries, or other factors, could negatively affect the Company's results of operations.
In 2023, 2022 and 2021, the Company experienced elevated commodity and supply chain costs including the costs of labor, raw materials, energy-related products and other inputs used in the production and distribution of its products and services. The Company's construction business tries to mitigate some or all cost increases through increases in selling prices, maintaining positive relationships with numerous raw material suppliers, and escalation clauses in contracting services contracts and fuel surcharges. To the extent price increases or other mitigating factors are not sufficient to offset these increased costs adequately or timely, and/or if the price increases result in a significant decrease in sales volumes, the Company's results of operations, financial position and cash flows could be negatively impacted.
Reductions in the Company's credit ratings could increase financing costs.
There is no assurance the Company's current credit ratings, or those of its subsidiaries, will remain in effect or that a rating will not be lowered or withdrawn by a rating agency. Events affecting the Company's financial results may impact its cash flows and credit metrics, potentially resulting in a change in the Company's credit ratings. The Company's credit ratings may also change as a result of the differing methodologies or changes in the methodologies used by the rating agencies.
Increasing costs associated with health care plans may adversely affect the Company's results of operations.
The Company's self-insured costs of health care benefits for eligible employees continues to increase. Increasing quantities of large individual health care claims and an overall increase in total health care claims could have an adverse impact on operating results, financial position and liquidity. Legislation related to health care could also change the Company's benefit program and costs.
The Company is exposed to risk of loss resulting from the nonpayment and/or nonperformance by the Company's customers and counterparties.
If the Company's customers or counterparties experience financial difficulties, which has occurred and may reoccur in the future, the Company could experience difficulty in collecting receivables. Nonpayment and/or nonperformance by the Company's customers and counterparties, particularly customers and counterparties of the Company’s pipeline and construction services businesses for large construction projects, could have a negative impact on the Company's results of operations and cash flows. The Company could also have indirect credit risk from participating in energy markets such as MISO in which credit losses are socialized to all participants.
Changes in tax law may negatively affect the Company's business.
Changes to federal, state and local tax laws have the ability to benefit or adversely affect the Company's earnings and customer costs. Significant changes to corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law at the time of deferral. Changes to the value of various tax credits could change the economics of resources and the resource selection for the electric generation business. Regulation incorporates changes in tax law into the rate-setting process for the regulated energy delivery businesses, which could create timing delays before the impact of changes are realized.
The Company's operations could be negatively impacted by import tariffs and/or other government mandates.
The Company operates in or provides services to capital intensive industries in which federal trade policies could significantly impact the availability and cost of materials. Imposed and proposed tariffs could significantly increase the prices and delivery lead times on raw materials and finished products that are critical to the Company and its customers, such as aluminum and steel. Prolonged lead times on the delivery of raw materials and further tariff increases on raw materials and finished products could adversely affect the Company's business, financial condition and results of operations.
Pandemics may have a negative impact on the Company's business operations, revenues, results of operations, liquidity and cash flows.
Pandemics have disrupted national, state and local economies. To the extent pandemics adversely impact the Company's businesses, operations, revenues, liquidity or cash flows, they could also have a heightened effect on other risks described in this section. The degree to which pandemics impact the Company depends on, among other things, federal and state mandates, actions taken by governmental authorities, availability, timing and effectiveness of vaccines being administered, and the pace and extent to which the economy recovers and operates under normal market conditions.
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Operational Risks
Significant portions of the Company’s natural gas pipelines and power generation and transmission facilities are aging. The aging infrastructure may require significant additional maintenance or replacement that could adversely affect the Company’s results of operations.
Certain risks increase as the Company's energy delivery infrastructure ages, including breakdown or failure of equipment, pipeline leaks and fires developing from power lines, all of which have occurred and may reoccur in the future resulting in material costs. Aging infrastructure is more prone to failure, which increases maintenance costs, unplanned outages and the need to replace facilities. Even if properly maintained, reliability may ultimately deteriorate and negatively affect the Company’s ability to serve its customers, which could result in increased costs associated with regulatory oversight. The costs associated with maintaining the aging infrastructure and capital expenditures for new or replacement infrastructure could cause rate volatility and/or regulatory lag in some jurisdictions. If, at the end of its life, the investment costs of a facility have not been fully recovered, the Company may be adversely affected if commissions do not allow such costs to be recovered in rates. Such impacts of aging infrastructure could adversely affect the Company’s results of operations and cash flows.
Additionally, hazards from aging infrastructure could result in serious injury, loss of human life, significant damage to property, environmental impacts and impairment of operations, which in turn could lead to substantial financial losses. The location of facilities near populated areas, including residential areas, business centers, industrial sites and other public gathering places, could increase the damages resulting from these risks. A major incident involving another natural gas system could lead to additional capital expenditures, increased regulation, and fines and penalties on natural gas utilities and pipelines. The occurrence of any of these events could adversely affect the Company’s results of operations, financial position and cash flows.
The Company's utility and pipeline operations are subject to planning risks.
Most electric and natural gas utility investments, including natural gas transmission pipeline investments, are made with the intent of being used for decades. In particular, electric transmission and generation resources are planned well in advance of when they are placed into service based upon resource plans using assumptions over the planning horizon, including sales growth, commodity prices, equipment and construction costs, regulatory treatment, available technology and public policy. Public policy changes and technology advancements related to areas such as energy efficient appliances and buildings, renewable and distributive electric generation and storage, carbon dioxide emissions, electric vehicle penetration, restrictions on or disallowance of new or existing services, and natural gas availability and cost may significantly impact the planning assumptions. Changes in critical planning assumptions may result in excess generation, transmission and distribution resources creating increased per customer costs and downward pressure on load growth. These changes could also result in a stranded investment if the Company is unable to fully recover the costs of its investments.
The regulatory approval, permitting, construction, startup and/or operation of pipelines, power generation and transmission facilities may involve unanticipated events, delays and unrecoverable costs.
The construction, startup and operation of natural gas pipelines and electric power generation and transmission facilities involve many risks, which may include delays; breakdown or failure of equipment; inability to obtain required governmental permits and approvals; inability to obtain or renew easements; public opposition; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel supply, off-take, transmission, transportation or other material agreements; contractor performance failures; changes in markets and market prices for power; cost increases and overruns; the risk of performance below expected levels of output or efficiency; and the inability to obtain full cost recovery in regulated rates. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.
Operating or other costs required to comply with current or potential pipeline safety regulations and potential new regulations under various agencies could be significant. The regulations require verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of certain lines. Increased emphasis on pipeline safety and increased regulatory scrutiny may result in penalties and higher costs of operations. If these costs are not fully recoverable from customers, they could have an adverse effect on the Company’s results of operations and cash flows.
The backlog at the Company's construction services business may not accurately represent future revenue.
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 the Company's backlog are subject to changes in the scope of services to be provided, as well as adjustments to the costs relating to the applicable contracts. Backlog may also be affected by project delays or cancellations resulting from weather conditions, external market factors and economic factors beyond the Company's control, among other things. Accordingly, there is no assurance that backlog will be realized. 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 revenue and net income expected to be earned in the following year and should not be relied upon as a stand-alone indicator of future revenues or net income.
The Company's participation in joint venture contracts may have a negative impact on its reputation, business operations, revenues, results of operations, liquidity and cash flows.
The Company enters into certain joint venture arrangements typically to bid and execute particular projects. Generally, these agreements are directly with a third-party client; however, services may be performed by the venture, the joint venture partners or a combination thereof. Engaging in joint venture contracts exposes the Company to risks and uncertainties, some of which are outside the Company's control.
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The Company is reliant on joint venture partners to satisfy their contractual obligations, including obligations to commit working capital and equity, and to perform the work as outlined in the agreement. Failure to do so could result in the Company providing additional investments or services to address such performance issues. If the Company is unable to satisfactorily resolve any partner performance issues, the customer could terminate the contract, opening the Company to legal liability which could negatively impact the Company's reputation, revenues, results of operations, liquidity and cash flows.
Supply chain disruptions may adversely affect Company operations.
The Company relies on third-party vendors and manufacturers to supply many of the materials necessary for its operations. Global logistic disruptions have impacted the flow of materials and restricted global trade flows. Manufacturers are competing for a limited supply of key commodities and logistical capacity which has impacted lead times, pricing, supply and demand. Disruptions or delays in receiving materials; price increases from suppliers or manufacturers; or inability to source needed materials, which has occurred and could reoccur, could adversely affect the Company’s results of operations, financial condition and cash flows.
Environmental and Regulatory Risks
The Company's operations could be adversely impacted by climate change.
Severe weather events, such as tornadoes, hurricanes, rain, drought, ice and snowstorms, and high and low temperature extremes, occur in regions in which the Company operates and maintains infrastructure. Climate change could change the frequency and severity of these weather events, which may create physical and financial risks to the Company. Such risks could have an adverse effect on the Company's financial condition, results of operations and cash flows. To date, the Company has not experienced any material impacts to its financial condition, results of operations or cash flows due to the physical effects of climate change.
Severe weather events may damage or disrupt the Company's electric and natural gas transmission and distribution facilities, which could result in disruption of service and ability to meet customer demand and increase maintenance or capital costs to repair facilities and restore customer service. The cost of providing service could increase if the frequency of severe weather events increases because of climate change or otherwise. The Company may not recover all costs related to mitigating these physical risks.
Increases in severe weather conditions or extreme temperatures may cause infrastructure construction projects to be delayed or canceled and limit resources available for such projects resulting in decreased revenue or increased project costs at the construction services business.
Utility customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent the largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use by its utility customers due to weather may require the Company to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather may result in decreased revenues. Extreme weather conditions, such as uncommonly long periods of high or low ambient temperature in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the Company's service territory could also have an impact on revenues. The Company buys and sells electricity that might be generated outside its service territory, depending upon system needs and market opportunities. Extreme temperatures may create high energy demand and raise electricity prices, which could increase the cost of energy provided to customers.
Climate change may impact a region’s economic health, which could impact revenues at all of the Company's businesses. The Company's financial performance is tied to the health of the regional economies served. The Company provides natural gas and electric utility service, as well as construction services, for some states and communities that are economically affected by the agriculture industry. Increases in severe weather events or significant changes in temperature and precipitation patterns could adversely affect the agriculture industry and, correspondingly, the economies of the states and communities affected by that industry.
The insurance industry may be adversely affected by severe weather events, which may impact availability of insurance coverage, insurance premiums and insurance policy terms.
The Company may be subject to litigation related to climate change. Costs of such litigation could be significant, and an adverse outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages, which could affect the Company's results of operations and cash flows if the costs are not recoverable in rates.
The price of energy also has an impact on the economic health of communities. The cost of additional regulatory requirements related to climate change, such as regulation of carbon dioxide emissions under the federal Clean Air Act, requirements to replace fossil fuels with renewable energy or credits, or other environmental regulation or taxes, could impact the availability of goods and the prices charged by suppliers, which would normally be borne by consumers through higher prices for energy and purchased goods, and could adversely impact economic conditions of areas served by the Company. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect the Company's ability to access capital markets or result in less competitive terms and conditions.
MDU Resources Group, Inc. Form 10-K 25
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The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.
The Company is subject to environmental laws and regulations affecting many aspects of its operations, including air and water quality, wastewater discharge, the generation, transmission and disposal of solid waste and hazardous substances, and other environmental considerations. These laws and regulations can increase capital, operating and other costs; cause delays as a result of litigation and administrative proceedings; and create compliance, remediation, containment, monitoring and reporting obligations, particularly relating to electric generation, and natural gas transmission and storage operations. Environmental laws and regulations can also require the Company to install pollution control equipment at its facilities, clean up spills and other contamination and correct environmental hazards, including payment of all or part of the cost to remediate sites where the Company's past activities, or the activities of other parties, caused environmental contamination. These laws and regulations generally require the Company to obtain and comply with a variety of environmental licenses, permits, inspections and other approvals and may cause the Company to shut down existing facilities due to difficulties in assuring compliance or where the cost of compliance makes operation of the facilities uneconomical. Although the Company strives to comply with all applicable environmental laws and regulations, public and private entities and private individuals may interpret the Company's legal or regulatory requirements differently and seek injunctive relief or other remedies against the Company. The Company cannot predict the outcome, financial or operational, of any such litigation or administrative proceedings.
Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain facilities; restrict the use of certain fuels; prohibit or restrict new or existing services; replace certain fuels with renewable fuels; retire and replace certain facilities; install pollution controls; remediate environmental impacts; remove or reduce environmental hazards; or forego or limit the development of resources. Revised or new laws and regulations that increase compliance and disclosure costs and/or restrict operations, particularly if costs are not fully recoverable from customers, could adversely affect the Company's results of operations and cash flows.
Stakeholder actions and increased regulatory activity related to environmental, social and governance matters, particularly climate change and reducing GHG emissions, could adversely impact the Company's operations, costs of or access to capital and impact or limit business plans.
The Company, primarily at its electric, natural gas distribution and pipeline businesses, is facing increasing stakeholder scrutiny related to environmental, social and governance matters. The Company has seen a rise in certain stakeholders, such as investors, customers, employees and lenders, placing increasing importance on the impacts and social cost associated with climate change. Concern that GHG emissions contribute to global climate change has led to international, federal, state and local legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. For example, the SEC has published proposed rules that would require significantly increased disclosures associated with climate change and other issues. The Company may experience significant future costs associated with compliance of such legislative actions. The Company’s primary GHG emission is carbon dioxide from fossil fuels combustion at Montana-Dakota's electric generating facilities, particularly its coal-fired facilities.
Treaties, legislation or regulations to reduce GHG emissions in response to climate change may be adopted that affect the Company's utility and pipeline operations by requiring additional energy conservation efforts or renewable energy sources, limiting emissions, imposing carbon taxes or other compliance costs; as well as other mandates that could significantly increase capital expenditures and operating costs or reduce demand for the Company's utility services. If the Company’s utility and pipeline operations do not receive timely and full recovery of GHG emission compliance costs from customers, then such costs could adversely impact the results of operations and cash flows. Significant reductions in demand for the Company's utility and pipeline services as a result of increased costs or emissions limitations could also adversely impact the results of operations and cash flows.
The Company monitors, analyzes and reports GHG emissions from its other operations as required by applicable laws and regulations. The Company will continue to monitor GHG regulations and their potential impact on operations.
Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the potential financial impact on its operations.
In addition, the increasing focus on climate change and stricter regulatory requirements may result in the Company facing adverse reputational risks associated with certain of its operations producing GHG emissions. There have also been efforts to discourage the investment community from investing in equity and debt securities of companies engaged in fossil fuel related business and pressuring lenders to limit funding to such companies. Additionally, some insurance carriers have indicated an unwillingness to insure assets and operations related to certain fossil fuels. Although the Company has not experienced difficulties in these areas, if the Company is unable to satisfy the increasing climate-related expectations of certain stakeholders, the Company may suffer reputational harm, which may cause its stock price to decrease or difficulty in accessing the capital or insurance markets. Such efforts, if successfully directed at the Company, could increase the costs of or access to capital or insurance and interfere with business operations and ability to make capital expenditures.
26 MDU Resources Group, Inc. Form 10-K
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Other Risks
The Company's various businesses are seasonal and subject to weather conditions that could adversely affect the Company's operations, revenues and cash flows.
The Company's results of operations could be affected by changes in the weather. Weather conditions influence the demand for electricity and natural gas and affect the price of energy commodities. Utility operations have historically generated lower revenues when weather conditions are cooler than normal in the summer and warmer than normal in the winter, particularly in jurisdictions that do not have weather normalization mechanisms in place. Where weather normalization mechanisms are in place, there is no assurance the Company will continue to receive such regulatory protection from adverse weather in future rates.
Adverse weather conditions, which have occurred and may reoccur, such as heavy or sustained rainfall or snowfall, droughts, storms, wind and colder weather may affect the demand for products and the ability to perform services at the construction business and affect ongoing operation and maintenance and construction activities for the electric and natural gas transmission and distribution businesses. In addition, severe weather can be destructive, causing outages and property damage, which could require additional remediation costs. As a result, unusual or adverse weather conditions could negatively affect the Company's results of operations, financial position and cash flows.
Competition exists in all of the Company's businesses.
The Company's businesses are subject to competition. Construction services' competition is based primarily on price and reputation for quality, safety and reliability. The electric utility and natural gas businesses also experience competitive pressures as a result of consumer demands, technological advances and other factors. The pipeline business competes with several pipelines for access to natural gas supplies and for transportation and storage business. New acquisition opportunities are subject to competitive bidding environments which impact prices the Company must pay to successfully acquire new properties and acquisition opportunities to grow its business. The Company's failure to effectively compete could negatively affect the Company's results of operations, financial position and cash flows.
The Company's operations may be negatively affected if it is unable to obtain, develop and retain key personnel and skilled labor forces.
The Company must attract, develop and retain executive officers and other professional, technical and skilled labor forces with the skills and experience necessary to successfully manage, operate and grow the Company's businesses. Due to the changing workforce demographics and a lack of younger employees who are qualified to replace employees as they retire and remote work opportunities, among other things, competition for these employees is high. In some cases competition for these employees is on a regional or national basis. At times of low unemployment, it can be difficult for the Company to attract and retain qualified and affordable personnel. A shortage in the supply of skilled personnel creates competitive hiring markets, increased labor expenses, decreased productivity and potentially lost business opportunities to support the Company's operating and growth strategies. Additionally, if the Company is unable to hire employees with the requisite skills, the Company may be forced to incur significant training expenses. As a result, the Company's ability to maintain productivity, relationships with customers, competitive costs, and quality services is limited by the ability to employ, retain and train the necessary skilled personnel and could negatively affect the Company's results of operations, financial position and cash flows.
The Company's construction services business may be exposed to warranty claims.
The Company, particularly its construction services business, may provide warranties guaranteeing the work performed against defects in workmanship and material. If warranty claims occur, they may require the Company to re-perform the services or to repair or replace the warranted item at a cost to the Company and could also result in other damages if the Company is not able to adequately satisfy warranty obligations. In addition, the Company may be required under contractual arrangements with customers to warrant any defects from subcontractors or failures in materials the Company purchased from third parties. While the Company generally requires suppliers to provide warranties that are consistent with those the Company provides to customers, if any of the suppliers default on their warranty obligations to the Company, the Company may nonetheless incur costs to repair or replace the defective materials. Costs incurred as a result of warranty claims could adversely affect the Company's results of operations, financial condition and cash flows.
The Company is a holding company and relies on cash from its subsidiaries to pay dividends.
The Company's investments in its subsidiaries comprise the Company's primary assets. The Company depends on earnings, cash flows and dividends from its subsidiaries to pay dividends on its common stock. Regulatory, contractual and legal limitations, as well as their capital requirements, affect the ability of the subsidiaries to pay dividends to the Company and thereby could restrict or influence the Company's ability or decision to pay dividends on its common stock, which could adversely affect the Company's stock price.
Costs related to obligations under MEPPs could have a material negative effect on the Company's results of operations and cash flows.
Various operating subsidiaries of the Company participate in MEPPs for employees represented by certain unions. The Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements between the operating subsidiaries and those unions.
The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously endangered or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are required to adopt RPs or FIPs to improve their funded status through increased contributions, reduced benefits or a combination of the two.
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The Company may also be required to increase its contributions to MEPPs if the other participating employers in such plans withdraw from the plans and are not able to contribute amounts sufficient to fund the unfunded liabilities associated with their participation in the plans. The amount and timing of any increase in the Company's required contributions to MEPPs may depend upon one or more factors, including the outcome of collective bargaining; actions taken by trustees who manage the plans; actions taken by the plans' other participating employers; the industry for which contributions are made; future determinations that additional plans reach endangered, seriously endangered or critical status; newly-enacted government laws or regulations and the actual return on assets held in the plans; among others. The Company could experience increased operating expenses as a result of required contributions to MEPPs, which could have an adverse effect on the Company's results of operations, financial position or cash flows.
In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan. The Company could also incur an additional withdrawal liability if its withdrawal from a plan is determined by that plan to be part of a mass withdrawal.
Technology disruptions or cyberattacks could adversely impact the Company's operations.
The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information technology and operation technology systems, including disaster recovery and backup systems and network infrastructure. While the Company has policies, procedures and processes in place designed to strengthen and protect these systems, they may be vulnerable to physical and cybersecurity failures or unauthorized access, due to:
•hacking,
•human error,
•theft,
•sabotage,
•malicious software,
•ransomware,
•third-party compromise,
•acts of terrorism,
•acts of war,
•acts of nature or
•other causes.
Although there are manual processes in place, should a compromise or system failure occur, interdependencies to technology may disrupt the Company's ability to fulfill critical business functions. This may include interruption of electric generation, transmission and distribution facilities, natural gas storage and pipeline facilities, any of which could adversely affect the Company's reputation, business, cash flows and results of operations or subject the Company to legal or regulatory liabilities and increased costs. Additionally, the Company's electric generation and transmission systems and natural gas pipelines are part of interconnected systems with other operators’ facilities; therefore, a cyber-related disruption in another operator’s system could negatively impact the Company's business.
The Company’s accounting systems and its ability to collect information and invoice customers for products and services could be disrupted. If the Company’s operations are disrupted, it could result in decreased revenues and remediation costs that could adversely affect the Company's results of operations and cash flows.
The Company is subject to cybersecurity and privacy laws, regulations and security directives of many government agencies, including TSA, FERC and NERC. NERC issues comprehensive regulations and standards surrounding the security of bulk power systems and continually updates these requirements, as well as establishing new requirements with which the utility industry must comply. As these regulations evolve, the Company may experience increased compliance costs and may be at higher risk for violating these standards. Experiencing a cybersecurity incident could cause the Company to be non-compliant with applicable laws and regulations, causing the Company to incur costs related to legal claims, proceedings and regulatory fines or penalties. The SEC has adopted new rules that require the Company to provide greater disclosures around cybersecurity risk management, strategy, and governance, as well as disclose the occurrence of material cybersecurity incidents. The Company cannot predict or estimate the amount of additional costs it will incur in order to comply with these rules or the timing of such costs. These rules may also require the Company to report a cybersecurity incident before the Company has been able to fully assess its impact or remediate the underlying issue. Efforts to comply with such reporting requirements could divert management's attention from the Company's incident response and could potentially reveal system vulnerabilities to threat actors. Failure to timely report incidents under these or other similar rules could also result in monetary fines, sanctions or subject the Company to other forms of liability. This regulatory environment is increasingly challenging and may present material obligations and risks to the Company's business, including significantly expanded compliance burdens, costs, and enforcement risks.
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The Company, through the ordinary course of business, requires access to sensitive customer, supplier, employee and Company data. While the Company has implemented extensive security measures, including limiting the amount of sensitive information retained, a breach of its systems could compromise sensitive data and could go unnoticed for some time. Such an event could result in negative publicity and reputational harm, remediation costs, legal claims and fines that could have an adverse effect on the Company's financial results. Third-party service providers that perform critical business functions for the Company or have access to sensitive information within the Company also may be vulnerable to security breaches and information technology risks that could adversely affect the Company.
The Company’s information systems experience ongoing and often sophisticated cyberattacks by a variety of sources with the apparent aim to breach the Company's cyber-defenses. The Company may face increased cyber risk due to the increased use of employee-owned devices, work from home arrangements, and the separation of Knife River. Although the incidents the Company has experienced to date have not had a material effect on its business, financial condition or results of operations, such incidents could have a material adverse effect in the future as cyberattacks continue to increase in frequency and sophistication. The Company is continuously reevaluating the need to upgrade and/or replace systems and network infrastructure. These upgrades and/or replacements could adversely impact operations by imposing substantial capital expenditures, creating delays or outages, or experiencing difficulties transitioning to new systems. System disruptions, if not anticipated and appropriately mitigated, could adversely affect the Company.
Artificial intelligence presents challenges that can impact our business by posing security risks to confidential or proprietary information and personal data.
The use of artificial intelligence, combined with an uncertain regulatory environment, may result in reputational harm, liability, or other adverse consequences to our business operations. The Company may adopt and integrate artificial intelligence tools into its systems for specific use cases after review by legal and information security. The Company’s vendors and third-party partners may incorporate artificial intelligence tools into their offerings with or without disclosing this use to us. The providers of these artificial intelligence tools may not meet existing or rapidly evolving regulatory or industry standards concerning privacy and data protection, which may result in a loss of intellectual property or confidential information and/or cause harm to the Company’s reputation and the public perception of the effectiveness of its security measures. Further, bad actors around the world use increasingly sophisticated methods, including the use of artificial intelligence, to engage in illegal activities involving the theft and misuse of personal information, confidential information, and intellectual property. Any of these outcomes could damage the Company’s reputation, result in the loss of valuable property and information and adversely impact its business.
General risk factors that could impact the Company's businesses.
The following are additional factors that should be considered for a better understanding of the risks to the Company. These factors may negatively impact the Company's financial results in future periods.
•Acquisition, disposal and impairments of assets or facilities.
•Changes in present or prospective electric generation.
•Population decline and demographic patterns in the Company's areas of service.
•The cyclical nature of large construction projects at certain operations.
•Labor negotiations or disputes.
•Succession planning.
•Attracting and retaining employees.
•Stockholder and environmental activism.
•Inability of contract counterparties to meet their contractual obligations.
•The inability to effectively integrate the operations and the internal controls of acquired companies.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
The Company has no unresolved comments with the SEC.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
SEC regulations require the Company to disclose certain information about proceedings arising under federal, state or local environmental provisions if the Company reasonably believes that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to SEC regulations, the Company has adopted a threshold of $1.0 million for purposes of determining whether disclosure of any such proceedings is required.
For information regarding legal proceedings required by this item, see Item 8 - Note 22, which is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company's common stock is listed on the New York Stock Exchange under the symbol "MDU."
As of December 31, 2023, the Company's common stock was held by approximately 9,200 stockholders of record.
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. Based on this anticipated future state as a pure-play regulated energy delivery business, the board of directors established a long-term dividend payout ratio target of 60 percent to 70 percent of regulated earnings. The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by agreements governing the Company's indebtedness, federal and state laws, and applicable regulatory limitations. For more information on factors that may limit the Company's ability to pay dividends, see Item 8 - Note 13.
The following table includes information with respect to the Company's purchase of equity securities:
ISSUER PURCHASES OF EQUITY SECURITIES
Period Total Number
of Shares
(or Units)
Purchased (1)
Average Price Paid per Share
(or Unit)
Total Number of Shares
(or Units) Purchased
as Part of Publicly
Announced Plans
or Programs (2)
Maximum Number (or
Approximate Dollar
Value) of Shares (or
Units) that May Yet Be
Purchased Under the
Plans or Programs (2)
October 1 through October 31, 2023 - - - -
November 1 through November 30, 2023 50,717 $18.73 - -
December 1 through December 31, 2023 - - - -
Total 50,717 $18.73 - -
(1) Represents MDU original issue shares of common stock in connection with annual stock grants made to the Company's non-employee directors.
(2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to repurchase equity securities.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.
Reserved.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.
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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.
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•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.
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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.
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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.
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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.
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•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.
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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
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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.
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•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.
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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
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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.
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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.
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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.
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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.
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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
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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.
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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
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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
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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
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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
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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.
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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
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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.
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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.
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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.
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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.
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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.
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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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to the impact of market fluctuations associated with commodity prices and interest rates. The Company has policies and procedures to assist in controlling these market risks and from time to time has utilized derivatives to manage a portion of its risk.
Interest rate risk
The Company uses fixed and variable rate long-term debt to partially finance capital expenditures, including acquisitions, and mandatory debt retirements. These debt agreements expose the Company to market risk related to changes in interest rates. The Company manages this risk by attempting to take advantage of favorable market conditions when timing the placement of long-term financing. The Company from time to time has utilized interest rate swap agreements to manage a portion of the Company's interest rate risk and may take advantage of such agreements in the future to minimize such risk. For additional information on the Company's long-term debt, see Item 8 - Notes 9 and 10. At December 31, 2023 and 2022, the Company had no outstanding interest rate hedges.
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The following table shows the amount of long-term debt, which excludes unamortized debt issuance costs and discount, and related weighted average interest rates, both by expected maturity dates, as of December 31, 2023.
2024 2025 2026 2027 2028 Thereafter Total Fair
Value
(Dollars in millions)
Long-term debt:
Fixed rate $ 61.3 $ 157.7 $ 140.7 $ 20.7 $ 75.7 $ 1,468.2 $ 1,924.3 $ 1,672.1
Weighted average interest rate
4.2 % 4.0 % 5.8 % 7.3 % 4.4 % 4.4 % 4.5 %
Variable rate $ - $ 190.0 $ - $ 46.1 $ 144.2 $ - $ 380.3 $ 380.3
Weighted average interest rate
- % 6.6 % - % 8.5 % 5.9 % - % 6.6 %
Commodity price risk
The Company enters into commodity price derivative contracts to minimize the price volatility associated with natural gas costs for its customers at its natural gas distribution segment. At December 31, 2023 and 2022, these contracts were not material. For more information on the Company's derivatives, see Item 8 - Note 2.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Management's Report on Internal Control Over Financial Reporting
The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013).
Based on our evaluation under the framework in Internal Control-Integrated Framework (2013), management concluded that the Company's internal control over financial reporting was effective as of December 31, 2023.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2023, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.
/s/ Nicole A. Kivisto
/s/ Jason L. Vollmer
Nicole A. Kivisto
Jason L. Vollmer
President and Chief Executive Officer Vice President, Chief Financial Officer and Treasurer
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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of MDU Resources Group, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 and December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2024, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Revenue from Contracts with Customers-Construction Contract Revenue-Refer to Notes 2 and 4 to the financial statements
Critical Audit Matter Description
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, contract costs, and contract profits. The accounting for these contracts involves judgment, particularly as it relates to the process of determining the contract revenues and estimating total costs and profit for the performance obligation. Assumptions as to the occurrence of future events and the likelihood and amount of variable consideration, including liquidated damages, performance bonuses or incentives, claims, unpriced change orders and penalties or index pricing are made during the contract performance period. The Company estimates variable consideration at the most likely amount it expects to be entitled to or expects to incur and includes estimated amounts in the transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved. For the year ended December 31, 2023, the Company recognized $2.8 billion of construction contract revenue.
Given the judgments necessary to account for the Company’s construction contracts including the use of estimates to determine the transaction price, total costs and profit for the performance obligations which are used to recognize revenue for construction contracts, auditing such estimates required extensive audit effort due to the volume and complexity of construction contracts and a high degree of auditor judgment when performing audit procedures and evaluating the results of those procedures.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s estimates of total costs and profit for the performance obligations used to recognize revenue for construction contracts included the following, among others:
•We tested the design and operating effectiveness of management's controls over construction contract revenue, including those over management’s estimation of total costs and profit for the performance obligations.
•We developed an expectation of the amount of construction contract revenues for certain performance obligations based on prior year markups, and taking into account current year events, applied to the construction contract costs in the current year and compared our expectation to the amount of construction contract revenues recorded by management.
•We selected a sample of construction contracts and performed the following:
•Evaluated whether the contracts were properly included in management’s calculation of construction contract revenue based on the terms and conditions of each contract, including whether continuous transfer of control to the customer occurred as progress was made toward fulfilling the performance obligation.
•Observed the work sites and inspecting the progress to completion for certain construction contracts.
•Compared the transaction prices, including estimated variable consideration, to the consideration expected to be received based on current rights and obligations under the contracts and any modifications that were agreed upon with the customers.
•Evaluated management’s identification of distinct performance obligations by evaluating whether the underlying goods and services were highly interdependent and interrelated.
•Tested the accuracy and completeness of the costs incurred to date for the performance obligation.
•Compared the total estimated contract revenue, including estimated variable consideration, to the consideration expected to be received based on current rights and obligations under the contracts and any modifications that were agreed upon with the customers.
•We evaluated the reasonableness of the estimated variable consideration in the contract revenue by:
◦Evaluating the information supporting management’s judgement as to the cause and contractual rights on the project
◦Testing the accuracy of the identification of the underlying costs associated with the variable consideration.
•Evaluated the estimates of total cost and profit for the performance obligation by:
◦Comparing total costs incurred to date to the costs management estimated to be incurred to date and selecting specific cost types to compare costs incurred to date to management's estimated costs at completion.
◦Evaluating management’s ability to achieve the estimates of total cost and profit by performing corroborating inquiries with the Company’s project managers and engineers, and comparing the estimates to management’s work plans, engineering specifications, and supplier contracts.
◦Comparing management’s estimates for the selected contracts to costs and profits of similar performance obligations, when applicable.
•Tested the mathematical accuracy of management’s calculation of construction contract revenue for the performance obligation.
•We evaluated management’s ability to estimate total costs and profits accurately by comparing actual costs and profits to management’s historical estimates for performance obligations that have been fulfilled.
Regulatory Matters-Impact of Rate Regulation on the Financial Statements-Refer to Notes 2 and 21 to the financial statements
Critical Audit Matter Description
Through the Company’s regulated utility businesses, it provides electric and natural gas services to customers, and generates, transmits, and distributes electricity. The Company is subject to rate regulation by federal and state utility regulatory agencies (collectively, the “Commissions”), which have jurisdiction with respect to the rates of electric and natural gas distribution companies in states where the Company operates. The Company’s regulated utility businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery, refund or future rate reduction of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income taxes.
Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on the Company’s investment in the regulated utility businesses. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations.
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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) refunds or future rate reduction to customers. Given management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the design and operating effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company and other public utilities in the Company’s significant jurisdictions, procedural memorandums, filings made by the Company or interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness, and for any evidence that might contradict management’s assertions.
•We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery, or a future reduction in rates.
•We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new regulatory assets or liabilities.
Goodwill - Natural Gas Distribution Reporting Unit - Refer to Notes 2 and 8 to the financial statements
Critical Audit Matter Description
The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of the reporting unit to its carrying value. The Company determines the fair value of its reporting units using the discounted cash flow model and the market approach. The determination of the fair value using the discounted cash flow model requires management to make significant estimates and assumptions related to forecasts of future cash flows, earnings before interest, taxes, depreciation, and amortization (EBITDA), long-term growth rates, and discount rates. The determination of the fair value using the market approach requires management to make significant assumptions related to EBITDA multiples and rate base transaction multiples. Changes in these assumptions could have a significant impact on either the fair value or the amount of any goodwill impairment charge. The goodwill balance was $489 million as of December 31, 2023, of which $346 million was allocated to the Natural Gas Distribution Reporting Unit (“Natural Gas Distribution”). The fair value of Natural Gas Distribution exceeded its carrying value as of the measurement date and, therefore, no impairment was recognized.
We identified goodwill for Natural Gas Distribution as a critical audit matter because of the significant estimates and assumptions management makes to estimate the fair value and the difference between its fair value and carrying value. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future cash flows, EBITDA, and selection of the discount rate, the long-term growth rate, and EBITDA and rate base transaction multiples.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the forecasts of future cash flows EBITDA, the discount rate, long-term growth rate, EBITDA and the rate base transaction multiples used by management to estimate the fair value of Natural Gas Distribution included the following, among others:
•We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of Natural Gas Distribution, such as controls related to management’s forecasts of future cash flows and EBITDA and the selection of the discount rate, long-term growth rate, EBITDA and rate base transaction multiples.
•We evaluated management’s ability to accurately forecast by comparing actual results to management’s historical forecasts.
•We evaluated the reasonableness of management’s forecasts by comparing the forecasts to (1) historical results, (2) internal communications to management and the Board of Directors, and (3) forecasted information included in the Company press releases as well as in analyst and industry reports of the Company and companies in its peer group.
•We evaluated the impact of changes in management’s forecasts from the October 31, 2023, annual measurement date to December 31, 2023.
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•With the assistance of our fair value specialists, we evaluated the reasonableness of the valuation methodology, discount rate, and long-term growth rate, including testing the underlying source information and the mathematical accuracy of the calculations, and developing a range of independent estimates and comparing those to the discount rate and long-term growth rate selected by management.
•With the assistance of our fair value specialists, we evaluated the EBITDA transaction multiples, including testing the underlying source information and mathematical accuracy of the calculations, and comparing the multiples selected by management to its guideline companies and transactions.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 22, 2024
We have served as the Company's auditor since 2002.
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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of MDU Resources Group, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of MDU Resources Group, Inc. and subsidiaries (the "Company") as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 22, 2024, expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 22, 2024
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Consolidated Statements of Income
Years ended December 31, 2023 2022 2021
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline $ 1,789,637 $ 1,736,397 $ 1,390,992
Non-regulated pipeline, construction services and other
2,867,703 2,705,387 2,063,444
Total operating revenues 4,657,340 4,441,784 3,454,436
Operating expenses:
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline 397,037 375,347 367,234
Non-regulated pipeline, construction services and other
2,573,835 2,450,347 1,842,697
Total operation and maintenance 2,970,872 2,825,694 2,209,931
Purchased natural gas sold 742,965 757,883 483,118
Depreciation and amortization
213,598 210,028 198,240
Taxes, other than income 196,046 186,173 157,991
Electric fuel and purchased power 107,881 92,007 74,105
Total operating expenses 4,231,362 4,071,785 3,123,385
Operating income 425,978 369,999 331,051
Realized gain on tax-free exchange of the retained shares in Knife River
186,556 - -
Other income 41,672 11,228 25,724
Interest expense 114,308 80,698 70,709
Income before income taxes 539,898 300,529 286,066
Income taxes 59,473 49,761 43,544
Income from continuing operations 480,425 250,768 242,522
Discontinued operations, net of tax (65,718) 116,721 135,609
Net income $ 414,707 $ 367,489 $ 378,131
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
Weighted average common shares outstanding - basic 203,640 203,358 202,076
Weighted average common shares outstanding - diluted 203,938 203,462 202,383
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Statements of Comprehensive Income
Years ended December 31, 2023 2022 2021
(In thousands)
Net income $ 414,707 $ 367,489 $ 378,131
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $15, $177 and $145 in 2023, 2022 and 2021, respectively
81 413 446
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $(201), $3,965 and $1,626 in 2023, 2022 and 2021, respectively
(646) 12,007 4,876
Amortization of postretirement liability losses included in net periodic benefit credit, net of tax of $78, $597 and $615 in 2023, 2022 and 2021, respectively
242 1,819 1,870
Reclassification of postretirement liability adjustment from regulatory asset, net of tax of $0, $(1,086) and $0 in 2023, 2022 and 2021, respectively
- (3,265) -
Postretirement liability adjustment (404) 10,561 6,746
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized gain (loss) on available-for-sale investments arising during the period, net of tax of $46, $(177) and $(67) in 2023, 2022 and 2021, respectively
173 (667) (252)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $11, $31 and $36 in 2023, 2022 and 2021, respectively
43 114 134
Net unrealized gain (loss) on available-for-sale investments
216 (553) (118)
Other comprehensive income (loss) (107) 10,421 7,074
Comprehensive income attributable to common stockholders $ 414,600 $ 377,910 $ 385,205
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Balance Sheets
December 31, 2023 2022
Assets (In thousands, except shares and per share amounts)
Current assets:
Cash, cash equivalents and restricted cash
$ 76,975 $ 70,428
Receivables, net 942,782 1,064,340
Inventories 87,392 64,248
Current regulatory assets 172,492 165,092
Prepayments and other current assets 84,082 55,123
Current assets of discontinued operations - 592,517
Total current assets 1,363,723 2,011,748
Noncurrent assets:
Property, plant and equipment 7,341,116 6,874,629
Less accumulated depreciation and amortization
2,220,206 2,098,298
Net property, plant and equipment 5,120,910 4,776,331
Goodwill 488,960 488,960
Other intangible assets, net 2,004 4,102
Regulatory assets 447,099 329,659
Investments 124,235 128,827
Operating lease right-of-use assets 74,363 73,502
Other 211,865 161,901
Noncurrent assets of discontinued operations - 1,685,751
Total noncurrent assets 6,469,436 7,649,033
Total assets $ 7,833,159 $ 9,660,781
Liabilities and Stockholders' Equity
Current liabilities:
Short-term borrowings $ 95,000 $ 38,500
Long-term debt due within one year 61,319 47,819
Accounts payable 475,215 525,560
Taxes payable 58,110 62,308
Dividends payable 25,461 45,245
Accrued compensation 85,512 59,470
Operating lease liabilities due within one year 22,884 21,307
Regulatory liabilities due within one year 70,761 26,440
Other accrued liabilities 181,471 156,031
Current liabilities of discontinued operations - 496,923
Total current liabilities 1,075,733 1,479,603
Noncurrent liabilities:
Long-term debt 2,236,904 2,317,848
Deferred income taxes 458,548 455,499
Asset retirement obligations 384,371 372,870
Regulatory liabilities 521,050 448,454
Operating lease liabilities 51,645 52,871
Other 199,675 180,603
Noncurrent liabilities of discontinued operations
- 765,904
Total noncurrent liabilities 3,852,193 4,594,049
Commitments and contingencies
Stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 203,689,090 at December 31, 2023 and 204,162,814 at December 31, 2022
203,689 204,163
Other paid-in capital 1,466,235 1,466,037
Retained earnings 1,253,693 1,951,138
Accumulated other comprehensive loss (18,384) (30,583)
Treasury stock at cost - 538,921 shares at December 31, 2022
- (3,626)
Total stockholders' equity 2,905,233 3,587,129
Total liabilities and stockholders' equity $ 7,833,159 $ 9,660,781
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Statements of Equity
Years ended December 31, 2023, 2022 and 2021
Other
Paid-in Capital Retained Earnings Accumu-lated
Other Compre-hensive Loss
Common Stock Treasury Stock
Shares Amount Shares Amount Total
(In thousands, except shares)
At December 31, 2020
201,061,198 $ 201,061 $ 1,371,385 $ 1,558,363 $ (48,078) (538,921) $ (3,626) $ 3,079,105
Net income - - - 378,131 - - - 378,131
Other comprehensive income
- - - - 7,074 - - 7,074
Dividends declared on common stock - - - (174,084) - - - (174,084)
Employee stock-based compensation - - 14,709 - - - - 14,709
Repurchase of common stock
- - - - - (392,294) (6,701) (6,701)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings - - (10,828) - - 392,294 6,701 (4,127)
Issuance of common stock 2,828,463 2,828 85,939 - - - - 88,767
At December 31, 2021
203,889,661 203,889 1,461,205 1,762,410 (41,004) (538,921) (3,626) 3,382,874
Net Income - - - 367,489 - - - 367,489
Other comprehensive income - - - - 10,421 - - 10,421
Dividends declared on common stock - - - (178,761) - - - (178,761)
Employee stock-based compensation - - 10,254 - - - - 10,254
Repurchase of common stock - - - - - (266,821) (7,399) (7,399)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings - - (12,303) - - 266,821 7,399 (4,904)
Issuance of common stock 273,153 274 6,881 - - - - 7,155
At December 31, 2022
204,162,814 204,163 1,466,037 1,951,138 (30,583) (538,921) (3,626) 3,587,129
Net income - - - 414,707 - - - 414,707
Other comprehensive loss
- - - - (107) - - (107)
Dividends declared on common stock - - - (142,033) - - - (142,033)
Employee stock-based compensation - - 6,781 - - - - 6,781
Repurchase of common stock - - - - - (153,622) (4,811) (4,811)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings - - (7,851) - - 153,622 4,811 (3,040)
Separation of Knife River
(538,921) (539) - (970,119) 12,306 538,921 3,626 (954,726)
Issuance of common stock 65,197 65 1,268 - - - - 1,333
At December 31, 2023
203,689,090 $ 203,689 $ 1,466,235 $ 1,253,693 $ (18,384) - $ - $ 2,905,233
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Statements of Cash Flows
Years ended December 31, 2023 2022 2021
(In thousands)
Operating activities:
Net income $ 414,707 $ 367,489 $ 378,131
Less: income (loss) from discontinued operations, net of tax (65,718) 116,721 135,609
Income from continuing operations 480,425 250,768 242,522
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
213,598 210,028 198,240
Deferred income taxes (4,414) 21,248 27,393
Provision for credit losses 13,624 5,595 1,037
Amortization of debt issuance costs 1,207 978 930
Employee stock-based compensation costs 6,309 8,982 12,857
Pension and postretirement benefit plan net periodic benefit credit (5,380) (7,323) (5,990)
Unrealized losses (gains) on investments (7,493) 10,207 (6,096)
Gains on sales of assets (8,521) (6,631) (6,418)
Gain on tax-free exchange of the retained shares in Knife River
(186,556) - -
Changes in current assets and liabilities, net of acquisitions:
Receivables 110,434 (330,809) (75,380)
Inventories (27,594) (15,555) 138
Other current assets (52,882) (9,404) (67,389)
Accounts payable (76,679) 172,664 25,511
Other current liabilities 66,997 7,569 3,462
Pension and postretirement benefit plan contributions (7,643) (82) (83)
Other noncurrent changes (22,675) (10,582) (51,787)
Net cash provided by continuing operations 492,757 307,653 298,947
Net cash (used in) provided by discontinued operations (160,130) 202,411 196,830
Net cash provided by operating activities 332,627 510,064 495,777
Investing activities:
Capital expenditures (519,726) (478,425) (485,197)
Acquisitions, net of cash acquired - - (2,500)
Net proceeds from sale or disposition of property
16,474 11,340 14,585
Cost of removal, net of salvage value
1,170 (11,780) (11,363)
Investments 16,302 (4,138) (3,136)
Net cash used in continuing operations (485,780) (483,003) (487,611)
Net cash used in discontinued operations (55,011) (155,878) (398,267)
Net cash used in investing activities (540,791) (638,881) (885,878)
Financing activities:
Issuance of short-term borrowings 810,000 38,500 50,000
Repayment of short-term borrowings (460,901) - (100,000)
Issuance of long-term debt 726,700 373,046 272,043
Repayment of long-term debt (792,998) (65,764) (24,758)
Debt issuance costs (2,521) (1,129) (918)
Proceeds from issuance of common stock - (150) 88,767
Dividends paid (161,316) (176,915) (171,354)
Repurchase of common stock (4,811) (7,399) (6,701)
Tax withholding on stock-based compensation (3,040) (4,904) (4,126)
Net cash provided by continuing operations 111,113 155,285 102,953
Net cash provided by (used in) discontinued operations 93,509 (112) 281,762
Net cash provided by financing activities 204,622 155,173 384,715
Increase (decrease) in cash, cash equivalents and restricted cash (3,542) 26,356 (5,386)
Cash, cash equivalents and restricted cash - beginning of year
80,517 54,161 59,547
Cash, cash equivalents and restricted cash - end of year *
$ 76,975 $ 80,517 $ 54,161
*Includes cash of discontinued operations of $10.1 million and $10.4 million for the years ended December 31, 2022 and 2021, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
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Notes to Consolidated Financial Statements
Note 1 - Basis of Presentation
The abbreviations and acronyms used throughout are defined following the Notes to Consolidated Financial Statements. The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline, construction services and other. The electric and natural gas distribution businesses, as well as a portion of the pipeline business, are regulated. Construction services and other, as well as a portion of the pipeline business, are non-regulated. For further descriptions of the Company's businesses, see Note 18.
The Company announced strategic initiatives in 2022 as part of the Company's continuous review of its business. 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.
The Company's consolidated financial statements and accompanying notes for the current and prior periods have been restated to present the results of operations and the assets and liabilities of Knife River as discontinued operations, other than certain corporate overhead costs of the Company historically allocated to Knife River, which are reflected in Other. Also included in discontinued operations in the Consolidated Statements of Income are the supporting activities of Fidelity and certain interest expense related to financing activity associated with the Knife River separation. The assets and liabilities of the Company's discontinued operations are included in current assets of discontinued operations, noncurrent assets of discontinued operations, current liabilities of discontinued operations and noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations.
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.
Management has also evaluated the impact of events occurring after December 31, 2023, up to the date of issuance of these consolidated financial statements on February 22, 2024, that would require recognition or disclosure in the financial statements.
Principles of consolidation
The consolidated financial statements were prepared in accordance with GAAP and include the accounts of the Company and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. For more information on intercompany revenues, see Note 18.
The statements also include the Company's ownership interests in the assets, liabilities and expenses of jointly owned electric transmission and generating facilities. See Note 20 for additional information.
Use of estimates
The preparation of financial statements in conformity with GAAP requires the Company 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. Estimates are used for items such as long-lived assets and goodwill; property depreciable lives; tax provisions; revenue recognized using the cost-to-cost measure of progress for contracts; expected credit losses; environmental and other loss contingencies; regulatory assets expected to be recovered in rates charged to customers; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; lease classification; present value of right-of-use assets and lease liabilities; and the valuation of stock-based compensation. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
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Note 2 - Significant Accounting Policies
New accounting standards
The following table provides a brief description of the accounting pronouncements applicable to the Company and the potential impact on its financial statements and or disclosures:
Standard Description Effective date Impact on financial statements/disclosures
Recently adopted accounting standards
ASU 2020-04 - Reference Rate Reform In March 2020, the FASB issued optional guidance to ease the facilitation of the effects of reference rate reform on financial reporting. The guidance applies to certain contract modifications, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. Beginning January 1, 2022, LIBOR or other discontinued reference rates cannot be applied to new contracts. New contracts will incorporate a new reference rate, which includes SOFR. LIBOR or other discontinued reference rates cannot be applied to contract modifications or hedging relationships entered into or evaluated after December 31, 2022. Existing contracts referencing LIBOR or other reference rates expected to be discontinued must identify a replacement rate by June 30, 2023. Effective as of March 12, 2020 through December 31, 2022 For more information, see ASU 2022-06 - Reference Rate Reform: Deferral of Sunset Date below.
ASU 2022-06 - Reference Rate Reform: Deferral of Sunset Date In December 2022, the FASB included a sunset provision within ASC 848 based on expectations of when LIBOR would cease being published. At the time ASU 2020-04 was issued, the UK Financial Conduct Authority had established its intent to cease overnight tenors of LIBOR after December 31, 2021. In March 2021, the UK Financial Conduct Authority announced that the intended cessation date of the overnight tenors of LIBOR would be June 30, 2023 which is beyond the current sunset date of ASC 848. The amendments in this Update defer the sunset date of ASC 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in ASC 848. December 31, 2024 The Company has updated its credit agreements to include language regarding the successor or alternate rate to LIBOR. The Company does not expect the guidance to have a material impact on its results of operations, financial position, cash flows or disclosures.
Recently issued accounting standards not yet adopted
ASU 2023-05 Business Combinations - Joint Venture Formations - Recognition and Initial Measurement
In August 2023, the FASB issued guidance on accounting for contributions made to a joint venture, upon formation, in a joint venture's separate financial statement in order to provide decision-useful information to investors and other allocators of capital (collectively investors) in a joint venture's financial statements and reduce diversity in practice. The new basis of accounting will require that a joint venture, upon formation, will recognize and initially measure its assets and liabilities at fair value (with the exceptions to fair value measurement that are consistent with the business combinations guidance). A joint venture that was formed before January 1, 2025 may elect to apply the guidance retrospectively if it has sufficient information.
Effective prospectively for all joint venture formations with a formation date on or after January 1, 2025.
The Company is currently evaluating the impact the guidance will have on its interim and annual disclosures for the year ended December 31, 2025.
ASU 2023-07 Segment Reporting - Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued guidance on improving financial reporting by requiring disclosure of incremental segment information, primarily through enhanced disclosures about significant segment expenses, on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses.
Effective for fiscal year December 31, 2024 and interim periods beginning January 1, 2025, with prior periods disclosed in the period of adoption.
The Company is currently evaluating the impact the guidance will have on its disclosures for the year ended December 31, 2024 and future interim periods.
ASU 2023-09 Income Taxes - Improvements to Income Tax Disclosures an Amendment, December 2023
The FASB issued guidance to address investors requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information and effectiveness of income tax disclosures.
December 31, 2025 The Company is currently evaluating the impact the guidance will have on its disclosures for the year ended December 31, 2025.
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Cash, cash equivalents and restricted cash
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Restricted cash represents deposits held by the Company’s captive insurance company that is required by state insurance regulations to remain in the captive insurance company. The Company had restricted cash of $28.1 million and $35.6 million at December 31, 2023 and 2022, respectively.
Revenue recognition
Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer and excludes any sales incentives and amounts collected on behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents revenues net of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.
The electric and natural gas distribution segments generate revenue from the sales of electric and natural gas products and services, which includes retail and transportation services. These segments establish a customer's retail or transportation service account based on the customer's application/contract for service, which indicates approval of a contract for service. The contract identifies an obligation to provide service in exchange for delivering or standing ready to deliver the identified commodity; and the customer is obligated to pay for the service as provided in the applicable tariff. The product sales are based on a fixed rate that includes a base and per-unit rate, which are included in approved tariffs as determined by state or federal regulatory agencies. The quantity of the commodity consumed or transported determines the total per-unit revenue. The service provided, along with the product consumed or transported, are a single performance obligation because both are required in combination to successfully transfer the contracted product or service to the customer. Revenues are recognized over time as customers receive and consume the products and services. The method of measuring progress toward the completion of the single performance obligation is on a per-unit output method basis, with revenue recognized based on the direct measurement of the value to the customer of the goods or services transferred to date. For contracts governed by the Company’s utility tariffs, amounts are billed monthly with the amount due between 15 and 22 days of receipt of the invoice depending on the applicable state’s tariff. For other contracts not governed by tariff, payment terms are net 30 days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.
The pipeline segment generates revenue from providing natural gas transportation and underground storage services, as well as other energy-related services to both third parties and internal customers, largely the natural gas distribution segment. The pipeline segment establishes a contract with a customer based upon the customer’s request for firm or interruptible natural gas transportation or storage service(s). The contract identifies an obligation for the segment to provide the requested service(s) in exchange for consideration from the customer over a specified term. Depending on the type of service(s) requested and contracted, the service provided may include transporting or storing an identified quantity of natural gas and/or standing ready to deliver or store an identified quantity of natural gas. Natural gas transportation and storage revenues are based on fixed rates, which may include reservation fees and/or per-unit commodity rates. The services provided by the segment are generally treated as single performance obligations satisfied over time simultaneous to when the service is provided and revenue is recognized. Rates for the segment’s regulated services are based on its FERC approved tariff or customer negotiated rates, and rates for its non-regulated services are negotiated with its customers and set forth in the contract. For contracts governed by the company’s tariff, amounts are billed on or before the ninth business day of the following month and the amount is due within 12 days of receipt of the invoice. For other contracts not governed by the tariff, payment terms are net 30 days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.
The construction services segment generates revenue from specialty contracting services which also includes the sale of construction equipment and other supplies. This segment provides specialty contracting services to a customer when a contract has been signed by both the customer and a representative of the segment obligating a service to be provided in exchange for the consideration identified in the contract. The nature of the services this segment provides generally includes multiple promised goods and services in a single project to create a distinct bundle of goods and services, which the Company has determined are single performance obligations. The transaction price includes the fixed consideration required pursuant to the original contract price together with any additional consideration, to which the Company expects to be entitled to, associated with executed change orders plus the estimate of variable consideration to which the Company expects to be entitled, subject to the following constraint. The nature of the segment's contracts gives rise to several types of variable consideration. Examples of variable consideration include: liquidated damages; performance bonuses or incentives and penalties; claims; unpriced change orders; and 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 determination of whether to include estimated amounts in the transaction price are based largely on the 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 or 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. Contract revenue is recognized over time using the input method based on the measurement of progress on a project. This is the preferred method of measuring revenue because the costs incurred have been determined to
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represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. 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 segment also sells construction equipment and other supplies to third parties and internal customers. The contract for these sales is the use of a sales order or invoice, which includes the pricing and payment terms. All such contracts include a single performance obligation for the delivery of a single distinct product or a distinct separately identifiable bundle of products and services. Revenue is recognized at a point in time when the performance obligation has been satisfied with the delivery of the products or services. The warranties associated with the sales are those consistent with a standard warranty that the product meets certain specifications for quality or those required by law. For most contracts, amounts billed to customers are due within 30 days of receipt. There are no material obligations for returns, refunds or other similar obligations.
The Company recognizes all other revenues when services are rendered or goods are delivered.
Legal costs
The Company expenses external legal fees as they are incurred.
Receivables and allowance for expected credit losses
Receivables consist primarily of trade and contracting services receivables from the sale of goods and services net of expected credit losses. The Company's trade receivables are all due in 12 months or less. The total balance of receivables past due 90 days or more was $45.7 million and $34.3 million at December 31, 2023 and 2022, respectively.
The Company's expected credit losses are determined through a review using historical credit loss experience, changes in asset specific characteristics, current conditions and reasonable and supportable future forecasts, among other specific account data, and is performed at least quarterly. The Company develops and documents its methodology to determine its allowance for expected credit losses at each of its reportable business segments. Risk characteristics used by the business segments may include customer mix, knowledge of customers and general economic conditions of the various local economies, among others. Specific account balances are written off when management determines the amounts to be uncollectible. Management has reviewed the balance reserved through the allowance for expected credit losses and believes it is reasonable.
Details of the Company's expected credit losses were as follows:
Electric Natural gas
distribution Pipeline Construction
services Total
(In thousands)
At December 31, 2021
$ 269 $ 1,506 $ 2 $ 2,533 $ 4,310
Current expected credit loss provision
1,325 4,084 - 186 5,595
Less write-offs charged against the allowance 1,625 4,913 - 625 7,163
Credit loss recoveries collected 406 938 - 68 1,412
At December 31, 2022 375 1,615 2 2,162 4,154
Current expected credit loss provision 1,645 5,777 - 6,202 13,624
Less write-offs charged against the allowance 1,994 7,355 2 455 9,806
Credit loss recoveries collected 388 1,152 - 58 1,598
At December 31, 2023 $ 414 $ 1,189 $ - $ 7,967 $ 9,570
Receivables also consist of accrued unbilled revenue representing revenues recognized in excess of amounts billed. Accrued unbilled revenue at MDU Energy Capital was $132.0 million and $181.8 million at December 31, 2023 and 2022, respectively.
Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows:
2023 2022
(In thousands)
Short-term retainage*
$ 84,474 $ 91,474
Long-term retainage**
21,355 19,511
Total retainage $ 105,829 $ 110,985
* Expected to be paid within 12 months or less and included in receivables, net.
** Included in noncurrent assets - other.
MDU Resources Group, Inc. Form 10-K 77
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Inventories and natural gas in storage
Natural gas in storage for the Company's regulated operations is generally valued at lower of cost or market using the last-in, first-out method or lower of cost or net realizable value using the average cost or first-in, first-out method. The majority of all other inventories are valued at the lower of cost or net realizable value using the average cost method. The portion of the cost of natural gas in storage expected to be used within 12 months was included in inventories. Inventories at December 31 consisted of:
2023 2022
(In thousands)
Natural gas in storage (current) $ 39,377 $ 22,533
Merchandise for resale 34,955 27,910
Materials and supplies 5,460 6,846
Other 7,600 6,959
Total $ 87,392 $ 64,248
The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in noncurrent assets - other and was $48.5 million and $47.5 million at December 31, 2023 and 2022, respectively.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, the resulting gains or losses are recognized as a component of income.
The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, on certain contracting services projects associated with its other operations. The amount of AFUDC for the years ended December 31 was as follows:
2023 2022 2021
(In thousands)
AFUDC - borrowed $ 10,035 $ 2,236 $ 2,833
AFUDC - equity $ 1,894 $ 2,165 $ 6,961
Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets.
The Company collects removal costs for certain plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities on the Consolidated Balance Sheets.
Impairment of long-lived assets, excluding goodwill
The Company reviews the carrying values of its long-lived assets, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The Company tests long-lived assets for impairment at a level significantly lower than that of goodwill impairment testing. Long-lived assets or groups of assets that are evaluated for impairment at the lowest level of largely independent identifiable cash flows at an individual operation or group of operations collectively serving a local market. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. The impairments are recorded in operation and maintenance expense on the Consolidated Statements of Income.
No impairment losses were recorded in 2023, 2022 or 2021. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments. Natural gas costs recoverable through rate adjustments were $154.3 million and $141.3 million at December 31, 2023 and 2022, respectively, which were included in current regulatory assets and noncurrent assets - regulatory assets on the Consolidated Balance Sheets. Natural gas costs refundable through rate adjustments were $43.2 million and $1.0 million at December 31, 2023 and 2022, respectively, which were included in regulatory liabilities due within one year on the Consolidated Balance Sheets.
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Electric fuel and purchased power deferral
Under the terms of certain orders of the applicable state public service commissions, the Company is deferring electric fuel and purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments. Electric fuel and purchased power costs recoverable were $33.9 million and $2.7 million at December 31, 2023 and 2022, respectively, which were included in current regulatory assets on the Consolidated Balance Sheets. Electric fuel and purchased power costs refundable was $4.9 million at December 31, 2022, which was included in regulatory liabilities due within one year on the Consolidated Balance Sheets.
Regulatory assets and liabilities
The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC as well as the provisions of ASC 980 - Regulated Operations. These accounting policies differ in some respects from those used by the Company's non-regulated businesses.
The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively. The Company records regulatory assets or liabilities at the time the Company determines the amounts to be recoverable in current or future rates. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commission. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which the Company completes in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.
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 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.
Investments
The Company's investments include the cash surrender value of life insurance policies, insurance contracts, mortgage-backed securities and U.S. Treasury securities. The Company measures its investment in the insurance contracts at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive loss. For more information, see Notes 9 and 19.
Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.
The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.
MDU Resources Group, Inc. Form 10-K 79
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Joint ventures
The Company accounts for unconsolidated joint ventures using either the equity method or proportionate consolidation. The Company currently holds interests of 50 percent in joint ventures formed primarily for the purpose of pooling resources on construction contracts. Proportionate consolidation is used for joint ventures that include unincorporated legal entities and activities of the joint venture which are construction-related. For those joint ventures accounted for under proportionate consolidation, only the Company’s pro rata share of assets, liabilities, revenues and expenses are included in the Company’s balance sheet and results of operations.
For those joint ventures accounted for using proportionate consolidation, the Company recorded in its Consolidated Statements of Income $7.8 million, $14.8 million, and $14.7 million of revenue for the years ended December 31, 2023, 2022 and 2021, respectively, and $2.1 million, $3.0 million and $4.7 million of operating income for the years ended December 31, 2023, 2022 and 2021, respectively. At December 31, 2023 and 2022, the Company had interest in assets from these joint ventures of $1.8 million and $2.4 million, respectively.
For those joint ventures accounted for under the equity method, the Company's investment balances for the joint venture is included in Investments in the Consolidated Balance Sheets and the Company’s pro rata share of net income is included in Other income in the Consolidated Statements of Income. The Company’s investments in equity method joint ventures were net assets of $6.2 million and $1.3 million at December 31, 2023 and 2022, respectively. In 2023, 2022 and 2021, the Company recognized income from equity method joint ventures of $4.9 million, $5.9 million and $878,000, respectively.
Derivative instruments
The Company enters into commodity price derivative contracts in order to minimize the price volatility associated with customer natural gas costs at its natural gas distribution segment. These derivatives are not designated as hedging instruments and are recorded in the Consolidated Balance Sheets at fair value. Changes in the fair value of these derivatives along with any contract settlements are recorded each period in regulatory assets or liabilities in accordance with regulatory accounting. The Company does not enter into any derivatives for trading or other speculative purposes.
The Company did not enter into any commodity price derivative contracts during 2023 or 2022.
Leases
Lease liabilities and their corresponding right-of-use assets are recorded based on the present value of lease payments over the expected lease term. The Company recognizes leases with an original lease term of 12 months or less in income on a straight-line basis over the term of the lease and does not recognize a corresponding right-of-use asset or lease liability. The Company determines the lease term based on the non-cancelable and cancelable periods in each contract. The non-cancelable period consists of the term of the contract that is legally enforceable and cannot be canceled by either party without incurring a significant penalty. The cancelable period is determined by various factors that are based on who has the right to cancel a contract. If only the lessor has the right to cancel the contract, the Company will assume the contract will continue. If the lessee is the only party that has the right to cancel the contract, the Company looks to asset, entity and market-based factors. If both the lessor and the lessee have the right to cancel the contract, the Company assumes the contract will not continue.
The discount rate used to calculate the present value of the lease liabilities is based upon the implied rate within each contract. If the rate is unknown or cannot be determined, the Company uses an incremental borrowing rate, which is determined by the length of the contract, asset class and the Company's borrowing rates, as of the commencement date of the contract.
Asset retirement obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its non-regulated operations or incurs a regulatory asset or liability at its regulated operations.
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Stock-based compensation
The Company determines compensation expense for stock-based awards based on the estimated fair values at the grant date and recognizes the related compensation expense over the vesting period. The Company uses the straight-line amortization method to recognize compensation expense related to restricted stock units, which only has a service condition. This method recognizes stock compensation expense on a straight-line basis over the requisite service period for the entire award. The Company recognized compensation expense related to performance awards that vest based on performance metrics and service conditions on a straight-line basis over the service period. Inception-to-date expense was adjusted based upon the determination of the potential achievement of the performance target at each reporting date. The Company recognized compensation expense related to performance awards with market-based performance metrics on a straight-line basis over the requisite service period. Outstanding performance share awards were converted to restricted stock units in connection with the completed separation of Knife River through the spinoff.
The Company records the compensation expense for performance share awards using an estimated forfeiture rate. The estimated forfeiture rate is calculated based on an average of actual historical forfeitures. The Company also performs an analysis of any known factors at the time of the calculation to identify any necessary adjustments to the average historical forfeiture rate. At the time actual forfeitures become more than estimated forfeitures, the Company records compensation expense using actual forfeitures.
Earnings per share
Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share is computed by dividing net income by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of nonvested performance share awards and restricted stock units. Common stock outstanding includes issued shares less shares held in treasury. As a result of the separation, the Company retained legal ownership of 538,921 shares of the Company's common stock that were historically owned by a subsidiary of Knife River and recorded in Treasury stock at cost. Following the separation, the 538,921 treasury shares were retired. The 538,921 shares of treasury stock did not have an impact on weighted-average shares outstanding, as they were not outstanding prior to being retired. Net income was the same for both the basic and diluted earnings per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings per share calculations follows:
2023 2022 2021
(In thousands, except per share amounts)
Weighted average common shares outstanding - basic 203,640 203,358 202,076
Effect of dilutive performance share awards 298 104 307
Weighted average common shares outstanding - diluted 203,938 203,462 202,383
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
Shares excluded from the calculation of diluted earnings per share - 14 -
Dividends declared per common share
$ .6950 $ .8750 $ .8550
Income taxes
The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as regulatory liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.
The Company records uncertain tax positions in accordance with accounting guidance on accounting for income taxes on the basis of a two-step process in which (1) the Company determines whether it is more-likely-than-not that the tax position will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, the Company recognizes the largest amount of the tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority. Tax positions that do not meet the more-likely-than-not criteria are reflected as a tax liability. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.
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Note 3 - Discontinued Operations
On May 31, 2023, the Company completed the previously announced separation of Knife River, its former construction materials and contracting segment, into a new publicly traded company. The separation was achieved through the Company's pro-rata distribution of approximately 90 percent of the outstanding shares of Knife River to the Company's common stockholders. To effect the separation, the Company distributed to its stockholders 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, with the Company retaining approximately 10 percent, or 5.7 million shares of Knife River common stock immediately following the separation. In the fourth quarter of 2023, the Company completed the tax-free exchange of its retained shares, reversed the associated deferred tax liability and recognized a gain of $186.6 million, which was reflected in continuing operations because the Company did not have continuing significant involvement in Knife River.
As a result of the separation, the historical assets and liabilities for Knife River have been classified as assets and liabilities of discontinued operations and the historical results of operations are shown in discontinued operations, net of tax, other than allocated general corporate overhead costs of the Company, which do not meet the criteria for income (loss) from discontinued operations. The Company’s consolidated financial statements and accompanying notes for prior periods have been restated. For the comparative periods, Knife River's operations are only reflected through May 2023, whereas 2022 and 2021 include the full twelve months from Knife River's operations.
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.
As a result of the separation, the Company retained legal ownership of 538,921 shares of the Company's common stock that were historically owned by a subsidiary of Knife River and recorded in Treasury stock at cost. Following the separation, the 538,921 treasury shares were retired.
The Company will provide to Knife River and Knife River will provide to the Company transition services in accordance with the TSA entered into on May 31, 2023. For the twelve months ended December 31, 2023, the Company received $2.9 million; and paid $823,000, for these related activities. The majority of the transition services are expected to be provided for a period of one year, however, no longer than two years after the separation.
Separation related costs of $47.8 million and $9.0 million, net of tax, were incurred during the twelve months ended December 31, 2023 and 2022, respectively. Separation costs incurred are presented in income (loss) from discontinued operations in the Consolidated Statements of Income. These charges primarily relate to transaction and third-party support costs, one-time business separation fees and related tax charges.
The Company had no assets or liabilities related to the discontinued operations of Knife River on its balance sheet as of December 31, 2023. The carrying amounts of the major classes of assets and liabilities of discontinued operations included in the Company’s Consolidated Balance Sheet at December 31, 2022 were as follows:
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December 31, 2022
Assets (In Thousands)
Current assets:
Cash and cash equivalents $ 10,090
Receivables, net 241,302
Inventories 323,277
Prepayments and other current assets 17,848
Total current assets of discontinued operations 592,517
Noncurrent assets:
Net property, plant and equipment 1,315,213
Goodwill 274,540
Other intangible assets, net 13,430
Investments 33,086
Operating lease right-of-use assets 45,872
Other 3,610
Total noncurrent assets of discontinued operations 1,685,751
Total assets of discontinued operations $ 2,278,268
Liabilities
Current liabilities:
Short-term borrowings $ 208,000
Long-term debt due within one year 30,211
Accounts payable 131,608
Taxes payable 8,502
Accrued compensation 29,192
Operating lease liabilities due within one year 13,210
Other accrued liabilities 76,200
Total current liabilities of discontinued operations 496,923
Noncurrent liabilities:
Long-term debt 445,546
Deferred income taxes 175,804
Asset retirement obligations 33,015
Operating lease liabilities 32,663
Other 78,876
Total noncurrent liabilities of discontinued operations 765,904
Total liabilities of discontinued operations $ 1,262,827
The reconciliation of the major classes of income and expense constituting pretax income (loss) from discontinued operations to the after-tax income (loss) from discontinued operations on the Consolidated Statements of Income were as follows:
2023 2022 2021
(In thousands)
Operating revenues $ 735,263 $ 2,532,280 $ 2,226,478
Operating expenses 769,440 2,328,051 2,022,976
Operating (loss) income
(34,177) 204,229 203,502
Other income (expense) 2,381 (3,849) 693
Interest expense 37,545 38,575 23,117
(Loss) income from discontinued operations before income taxes
(69,341) 161,805 181,078
Income taxes (3,623) 45,084 45,469
Discontinued operations, net of tax $ (65,718) $ 116,721 $ 135,609
MDU Resources Group, Inc. Form 10-K 83
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Note 4 - Revenue from Contracts with Customers
Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer and excludes any sales incentives and amounts collected on behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents revenues net of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.
As part of the adoption of ASC 606 - Revenue from Contracts with Customers, the Company elected the practical expedient to recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that the Company otherwise would have recognized is 12 months or less.
Changes in cost estimates on certain contracts may result in the issuance of change orders, which can be approved or unapproved by the customer, or the assertion of contract claims. The Company recognizes amounts associated with change orders and claims as revenue if it is probable that the contract price will be adjusted and the amount of any such adjustment can be reasonably estimated. Change orders and claims are negotiated in the normal course of business and represent management’s estimates of additional contract revenues that have been earned and are probable of collection.
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.
Disaggregation
In the following table, revenue is disaggregated by the type of customer or service provided. The Company believes this level of disaggregation best depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. The table also includes a reconciliation of the disaggregated revenue by reportable segments. For more information on the Company's business segments, see Note 18.
Year ended December 31, 2023 Electric Natural gas distribution Pipeline Construction services Other Total
(In thousands)
Residential utility sales
$ 136,274 $ 724,600 $ - $ - $ - $ 860,874
Commercial utility sales 170,321 442,507 - - - 612,828
Industrial utility sales 43,063 45,205 - - - 88,268
Other utility sales 7,270 - - - - 7,270
Natural gas transportation - 52,465 145,297 - - 197,762
Natural gas storage - - 18,254 - - 18,254
Electrical & mechanical specialty contracting - - - 2,125,536 - 2,125,536
Transmission & distribution specialty contracting - - - 683,342 - 683,342
Other 54,508 15,141 13,874 173 7,941 91,637
Intersegment eliminations (274) (416) (62,540) (143) (7,941) (71,314)
Revenues from contracts with customers 411,162 1,279,502 114,885 2,808,908 - 4,614,457
Other revenues (10,261) 7,619 187 45,338 - 42,883
Total external operating revenues $ 400,901 $ 1,287,121 $ 115,072 $ 2,854,246 $ - $ 4,657,340
84 MDU Resources Group, Inc. Form 10-K
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Year ended December 31, 2022 Electric Natural gas distribution Pipeline Construction services Other Total
(In thousands)
Residential utility sales $ 138,634 $ 718,191 $ - $ - $ - $ 856,825
Commercial utility sales 146,182 453,802 - - - 599,984
Industrial utility sales 43,766 41,710 - - - 85,476
Other utility sales 7,597 - - - - 7,597
Natural gas transportation - 48,886 129,290 - - 178,176
Natural gas storage - - 14,583 - - 14,583
Electrical & mechanical specialty contracting - - - 1,988,729 - 1,988,729
Transmission & distribution specialty contracting - - - 662,705 - 662,705
Other 45,608 13,617 11,450 436 5,840 76,951
Intersegment eliminations (137) (274) (58,884) (4,627) (5,840) (69,762)
Revenues from contracts with customers 381,650 1,275,932 96,439 2,647,243 - 4,401,264
Other revenues (4,714) (2,402) 256 47,380 - 40,520
Total external operating revenues $ 376,936 $ 1,273,530 $ 96,695 $ 2,694,623 $ - $ 4,441,784
Year ended December 31, 2021 Electric Natural gas distribution Pipeline Construction services Other Total
(In thousands)
Residential utility sales $ 126,841 $ 544,721 $ - $ - $ - $ 671,562
Commercial utility sales 137,556 328,285 - - - 465,841
Industrial utility sales 41,757 30,964 - - - 72,721
Other utility sales 7,051 - - - - 7,051
Natural gas transportation - 48,408 114,001 - - 162,409
Natural gas storage - - 14,680 - - 14,680
Electrical & mechanical specialty contracting - - - 1,324,419 - 1,324,419
Transmission & distribution specialty contracting - - - 677,074 - 677,074
Other 42,902 10,567 13,667 557 4,606 72,299
Intersegment eliminations (170) (300) (59,470) (1,403) (4,522) (65,865)
Revenues from contracts with customers 355,937 962,645 82,878 2,000,647 84 3,402,191
Other revenues (6,525) 8,995 188 49,587 - 52,245
Total external operating revenues $ 349,412 $ 971,640 $ 83,066 $ 2,050,234 $ 84 $ 3,454,436
Contract balances
The timing of revenue recognition may differ from the timing of invoicing to customers. The timing of invoicing to customers does not necessarily correlate with the timing of revenues being recognized under the cost-to-cost method of accounting. Contracts from contracting services are billed as work progresses in accordance with agreed upon contractual terms. Generally, billing to the customer occurs contemporaneous to revenue recognition. A variance in timing of the billings may result in a contract asset or a contract liability. A contract asset occurs when revenues are recognized under the cost-to-cost measure of progress, which exceeds amounts billed on uncompleted contracts. Such amounts will be billed as standard contract terms allow, usually based on various measures of performance or achievement. A contract liability occurs when there are billings in excess of revenues recognized under the cost-to-cost measure of progress on uncompleted contracts. Contract liabilities decrease as revenue is recognized from the satisfaction of the related performance obligation.
The changes in contract assets and liabilities were as follows:
December 31, 2023 December 31, 2022 Change Location on Consolidated Balance Sheets
(In thousands)
Contract assets
$ 158,861 $ 154,144 $ 4,717 Receivables, net
Contract liabilities - current (202,144) (168,361) (33,783) Accounts payable
Contract liabilities - noncurrent (291) (6) (285) Noncurrent liabilities - other
Net contract liabilities $ (43,574) $ (14,223) $ (29,351)
MDU Resources Group, Inc. Form 10-K 85
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December 31, 2022 December 31, 2021 Change Location on Consolidated Balance Sheets
(In thousands)
Contract assets
$ 154,144 $ 103,737 $ 50,407 Receivables, net
Contract liabilities - current (168,361) (146,792) (21,569) Accounts payable
Contract liabilities - noncurrent (6) (118) 112 Noncurrent liabilities - other
Net contract liabilities $ (14,223) $ (43,173) $ 28,950
The Company recognized $167.7 million and $143.6 million in revenue for the years ended December 31, 2023 and 2022, respectively, which was previously included in contract liabilities at December 31, 2022 and 2021, respectively.
The Company recognized a net increase in revenues of $45.7 million and $46.9 million for the years ended December 31, 2023 and 2022, respectively, from performance obligations satisfied in prior periods.
Remaining performance obligations
The remaining performance obligations, also referred to as backlog, at the construction services segment include unrecognized revenues that the Company reasonably expects to be realized. These unrecognized revenues can include: projects that have a written award, a letter of intent, a notice to proceed, an agreed upon work order to perform work on mutually accepted terms and conditions and change orders or claims to the extent management believes additional contract revenues will be earned and are deemed probable of collection. Excluded from remaining performance obligations are potential orders under master service agreements. The majority of the Company's construction contracts have an original duration of less than two years.
The remaining performance obligations at the pipeline segment include firm transportation and storage contracts with fixed pricing and fixed volumes. The Company has applied the practical expedient that does not require additional disclosures for contracts with an original duration of less than 12 months to certain firm transportation and non-regulated contracts. The Company's firm transportation and storage contracts included in the remaining performance obligations have weighted average remaining durations of less than five years and two years, respectively.
At December 31, 2023, the Company's remaining performance obligations were $2.6 billion. The Company expects to recognize the following revenue amounts in future periods related to these remaining performance obligations: $1.6 billion within the next 12 months or less; $471.5 million within the next 13 to 24 months; and $529.2 million in 25 months or more.
86 MDU Resources Group, Inc. Form 10-K
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Note 5 - Property, Plant and Equipment
Property, plant and equipment at December 31 was as follows:
2023 2022 Weighted
Average
Depreciable
Life in Years
(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation $ 939,474 $ 938,614 48
Distribution 521,215 489,351 47
Transmission 639,999 616,611 65
Construction in progress 115,103 87,003 0
Other 153,248 145,034 15
Natural gas distribution:
Distribution 2,771,540 2,569,921 53
Transmission 115,057 104,769 54
Storage 42,654 42,318 37
General 215,572 204,993 13
Construction in progress 70,373 55,759 0
Other 246,991 230,299 15
Pipeline:
Transmission 1,035,995 951,187 46
Storage 57,160 55,383 53
Construction in progress 55,832 34,655 0
Other 63,867 59,917 18
Non-regulated:
Pipeline:
Construction in progress 1,206 49 0
Other 4,327 6,950 9
Construction services:
Land 8,662 8,234 0
Buildings and improvements 52,667 50,776 23
Machinery, vehicles and equipment 191,802 179,459 7
Other 6,718 6,642 4
Other:
Land 2,289 2,648 0
Other 29,365 34,057 7
Less accumulated depreciation and amortization
2,220,206 2,098,298
Net property, plant and equipment $ 5,120,910 $ 4,776,331
MDU Resources Group, Inc. Form 10-K 87
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Note 6 - Regulatory Assets and Liabilities
The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
Estimated Recovery or Refund Period * 2023 2022
(In thousands)
Regulatory assets:
Current:
Natural gas costs recoverable through rate adjustments Up to 1 year
$ 98,844 $ 141,306
Electric fuel and purchased power deferral Up to 1 year
33,918 2,656
Conservation programs Up to 1 year
14,425 8,544
Cost recovery mechanisms Up to 1 year
9,153 4,019
Environmental compliance programs Up to 1 year
5,525 -
Other Up to 1 year
10,627 8,567
172,492 165,092
Noncurrent:
Pension and postretirement benefits ** 142,511 143,349
Cost recovery mechanisms Up to 25 years
85,944 67,171
Environmental compliance programs - 66,806 -
Natural gas costs recoverable through rate adjustments Up to 2 years
55,493 -
Plant costs/asset retirement obligations Over plant lives 46,009 44,462
Manufactured gas plant site remediation - 26,127 26,624
Taxes recoverable from customers Over plant lives 12,249 12,330
Long-term debt refinancing costs Up to 37 years
2,600 3,188
Plant to be retired - 772 21,525
Other Up to 15 years
8,588 11,010
447,099 329,659
Total regulatory assets $ 619,591 $ 494,751
Regulatory liabilities:
Current:
Natural gas costs refundable through rate adjustments Up to 1 year
$ 43,161 $ 955
Provision for rate refund Up to 1 year
6,866 1,147
Cost recovery mechanisms Up to 1 year
6,284 1,977
Margin sharing Up to 1 year
5,243 -
Taxes refundable to customers Up to 1 year
2,149 3,937
Conservation programs Up to 1 year
2,130 4,126
Refundable fuel & electric costs Up to 1 year
263 3,253
Electric fuel and purchased power deferral Up to 1 year
- 4,929
Other Up to 1 year
4,665 6,116
70,761 26,440
Noncurrent:
Plant removal and decommissioning costs Over plant lives 220,147 208,650
Taxes refundable to customers Over plant lives 193,578 203,222
Environmental compliance programs - 61,941 -
Cost recovery mechanisms Up to 18 years
21,791 14,025
Accumulated deferred investment tax credit Over plant lives 15,740 13,594
Pension and postretirement benefits ** 6,044 7,376
Other Up to 14 years
1,809 1,587
521,050 448,454
Total regulatory liabilities $ 591,811 $ 474,894
Net regulatory position $ 27,780 $ 19,857
*Estimated recovery or refund period for amounts currently being recovered or refunded in rates to customers.
** Recovered as expense is incurred or cash contributions are made.
88 MDU Resources Group, Inc. Form 10-K
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As of December 31, 2023 and 2022, approximately $194.3 million and $242.5 million, respectively, of regulatory assets were not earning a rate of return but are expected to be recovered from customers in future rates. These assets are largely comprised of the unfunded portion of pension and postretirement benefits, asset retirement obligations, certain pipeline integrity costs, the estimated future cost of manufactured gas plant site remediation and the costs associated with environmental compliance.
The Company is subject to environmental compliance regulations in certain states which require natural gas distribution companies to reduce overall GHG emissions to certain thresholds as established by each applicable state. Compliance with these standards may be achieved through increased energy efficiency and conservation measures, purchased emission allowances and offsets and purchases of low carbon fuels. Emission allowances are allocated by the respective states to the Company at no cost, of which a portion is required to be sold at auction. The Company expects the compliance costs for these regulations and the revenues from the sale of the allocated emissions allowances will be passed through to customers in rates and has, accordingly, deferred the environmental compliance costs as a regulatory asset and proceeds from the sale of allowances as a regulatory liability.
In the last half of 2021 through 2022, the Company experienced high natural gas costs due to increase in demand outpacing the supply along with the impact of global events. Additionally, 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.
For a discussion of the Company's most recent cases by jurisdiction, see Note 20.
In February 2019, the Company announced the retirement of three aging coal-fired electric generating units. The Company accelerated the depreciation related to these facilities in property, plant and equipment and recorded the difference between the accelerated depreciation, in accordance with GAAP, and the depreciation approved for rate-making purposes as regulatory assets. Requests were filed with the NDPSC, MTPSC and SDPUC, and subsequently approved, to offset the savings associated with the cessation of operations of these units with the amortization of the deferred regulatory assets. The Company ceased operations of Lewis & Clark Station in March 2021 and Units 1 and 2 at Heskett Station in February 2022. The Company subsequently reclassified the costs being recovered for these facilities from plant retirement to cost recovery mechanisms in the previous table and began amortizing the associated plant retirement and closure costs.
If, for any reason, the Company's regulated businesses cease to meet the criteria for application of regulatory accounting for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income or accumulated other comprehensive loss in the period in which the discontinuance of regulatory accounting occurs.
Note 7 - Environmental Allowances and Obligations
Beginning in 2023, the Company's natural gas distribution segment acquires environmental allowances as part of its requirement to comply with environmental regulations in certain states. Allowances are allocated by the respective states to the Company at no cost and additional allowances are required to be purchased as needed based on the requirements in the respective states. The segment records purchased and allocated environmental allowances at weighted average cost under the inventory method of accounting. Environmental allowances are included in prepayments and other current assets and noncurrent assets - other on the Consolidated Balance Sheets. At December 31, 2023, the Company had $72.7 million of environmental allowances.
Environmental compliance obligations, which are based on GHG emissions, are measured at the carrying value of environmental allowances held plus the estimated value of additional allowances necessary to satisfy the compliance obligation. Environmental compliance obligations are included in current liabilities - other accrued liabilities and noncurrent liabilities - other on the Consolidated Balance Sheets. At December 31, 2023, the Company accrued $66.8 million in compliance obligations.
The Company recognizes revenue from the sale of emissions allowances allocated under the environmental programs when the allowances are sold at auction. The revenues associated with the sale of these allowances are deferred as a component of the respective jurisdiction’s regulatory liability for environmental compliance. At December 31, 2023, the Company received $61.9 million for the sale of emissions allowances.
As environmental allowances are surrendered, the segment reduces the associated environmental compliance assets and liabilities from the Consolidated Balance Sheets. The expenses and revenues associated with the Company’s environmental allowances and obligations are deferred as regulatory assets and liabilities. For more information on the Company’s regulatory assets and liabilities, see Note 6.
MDU Resources Group, Inc. Form 10-K 89
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Note 8 - Goodwill and Other Intangible Assets
The carrying amount of goodwill at the natural gas distribution and construction services segments, which remained unchanged, was $345.7 million and $143.2 million, respectively, at both December 31, 2023 and 2022. No impairments of goodwill have been recorded in these periods.
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 units 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.
Other amortizable intangible assets at December 31 were as follows:
2023 2022
(In thousands)
Customer relationships $ 10,450 $ 10,450
Less accumulated amortization 8,446 6,356
2,004 4,094
Noncompete agreements 292 552
Less accumulated amortization 292 544
- 8
Total $ 2,004 $ 4,102
Amortization expense for amortizable intangible assets for the years ended December 31, 2023, 2022 and 2021, was $2.1 million, $2.2 million and $2.5 million, respectively. The amounts of estimated amortization expense for identifiable intangible assets as of December 31, 2023, were:
2024 2025 2026 2027 2028 Thereafter
(In thousands)
Amortization expense $ 1,888 $ 116 $ - $ - $ - $ -
Note 9 - Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The fair value ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.
The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of insurance contracts, to satisfy its obligations under its unfunded, nonqualified defined benefit and defined contribution plans for the Company's executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $66.2 million and $78.0 million at December 31, 2023 and 2022, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized gain on these investments for the year ended December 31, 2023, was $7.5 million. The net unrealized loss on these investments for the year ended December 31, 2022 was $11.3 million. The net unrealized gain on these investments for the year ended December 31, 2021 was $5.8 million. The change in fair value, which is considered part of the cost of the plan, is classified in other income on the Consolidated Statements of Income. In 2023, the Company withdrew $20.0 million of its cost basis, which reduced investments on the Consolidated Balance Sheets at December 31, 2023.
The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in accumulated other comprehensive loss. Details of available-for-sale securities were as follows:
December 31, 2023 Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair Value
(In thousands)
Mortgage-backed securities $ 8,234 $ 17 $ 470 $ 7,781
U.S. Treasury securities 3,521 28 8 3,541
Total $ 11,755 $ 45 $ 478 $ 11,322
90 MDU Resources Group, Inc. Form 10-K
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December 31, 2022 Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair Value
(In thousands)
Mortgage-backed securities $ 8,928 $ 2 $ 636 $ 8,294
U.S. Treasury securities 2,608 - 72 2,536
Total $ 11,536 $ 2 $ 708 $ 10,830
The Company's assets measured at fair value on a recurring basis were as follows:
Fair Value Measurements at December 31, 2023, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2023
(In thousands)
Assets:
Money market funds $ - $ 6,409 $ - $ 6,409
Insurance contracts* - 66,283 - 66,283
Available-for-sale securities:
Mortgage-backed securities - 7,781 - 7,781
U.S. Treasury securities - 3,541 - 3,541
Total assets measured at fair value $ - $ 84,014 $ - $ 84,014
*The insurance contracts invest approximately 60 percent in fixed-income investments, 15 percent in common stock of large-cap companies, 8 percent in target date investments, 7 percent in common stock of mid-cap companies, 5 percent in common stock of small-cap companies, 3 percent in cash equivalents, 1 percent in high yield investments and 1 percent in international investments.
Fair Value Measurements at December 31, 2022, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2022
(In thousands)
Assets:
Money market funds $ - $ 4,913 $ - $ 4,913
Insurance contracts* - 77,958 - 77,958
Available-for-sale securities:
Mortgage-backed securities - 8,294 - 8,294
U.S. Treasury securities - 2,536 - 2,536
Total assets measured at fair value $ - $ 93,701 $ - $ 93,701
*The insurance contracts invest approximately 63 percent in fixed-income investments, 15 percent in common stock of large-cap companies, 8 percent in common stock of mid-cap companies, 6 percent in common stock of small-cap companies, 6 percent in target date investments and 2 percent in cash equivalents.
The Company's money market funds are valued at the net asset value of shares held at the end of the period, based on published market quotations on active markets, or using other known sources including pricing from outside sources. The estimated fair value of the Company's mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources. The estimated fair value of the Company's insurance contracts is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.
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The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable.
The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was categorized as Level 2 in the fair value hierarchy and was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt at December 31 was as follows:
2023 2022
(In thousands)
Carrying Amount $ 2,298,223 $ 2,365,667
Fair Value $ 2,046,039 $ 2,053,396
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
Note 10 - Debt
Due to the Knife River separation, Centennial repaid all of its outstanding debt in the second quarter of 2023, which was funded 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.
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.
The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries:
Company Facility Facility
Limit Amount Outstanding at December 31, 2023
Amount Outstanding at December 31, 2022
Letters of
Credit at December 31, 2023
Expiration
Date
(In millions)
Montana-Dakota Utilities Co. Commercial paper/Revolving credit agreement (a) $ 200.0 $ 144.2 $ 117.5 $ - 10/18/28
Cascade Natural Gas Corporation
Revolving credit agreement
$ 100.0 (b) $ 15.4 $ 44.4 $ 25.0 (c) 11/30/27
Intermountain Gas Company
Revolving credit agreement
$ 100.0 (d) $ 30.7 $ 85.6 $ - 10/13/27
Centennial Energy Holdings, Inc.
Commercial paper/Revolving credit agreement (e) $ - $ - $ 231.6 $ - 12/19/24
MDU Resources Group, Inc. Revolving credit agreement
$ 150.0 $ - $ - $ - 5/29/24
MDU Resources Group, Inc. Revolving credit agreement
$ 200.0 (f)
$ - $ - $ 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 and 2022, 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)Centennial repaid all of its outstanding debt in the second quarter of 2023, which was funded by the Knife River repayment and the Company entering into various new debt instruments. The commercial paper program was supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $700.0 million). At December 31, 2022, there was no amount outstanding under the revolving credit agreement.
(f)Certain provisions allow for increased borrowings, up to a maximum of $250.0 million.
Montana-Dakota's commercial paper programs are 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.
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Short-term debt
Cascade 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.
Intermountain 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.
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.
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.
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.
Long-term debt
Long-term Debt Outstanding Long-term debt outstanding was as follows:
Weighted Average Interest Rate at December 31, 2023
2023 2022
(In thousands)
Senior Notes due on dates ranging from July 15, 2024 to June 15, 2062
4.46 % $ 1,882,000 $ 1,848,500
Commercial paper supported by revolving credit agreements
5.94 % 144,200 349,050
Term Loan Agreements due on May 31, 2025 and September 3, 2032
6.51 % 196,300 7,000
Credit agreements due on October 13, 2027 and November 30, 2027
8.50 % 46,100 130,000
Medium-Term Notes due on dates ranging from September 15, 2027 to March 16, 2029
7.32 % 35,000 35,000
Other notes due on dates ranging from May 31, 2028 to November 30, 2038
2.21 % 980 1,614
Less unamortized debt issuance costs 6,357 5,211
Less discount - 286
Total long-term debt 2,298,223 2,365,667
Less current maturities 61,319 47,819
Net long-term debt $ 2,236,904 $ 2,317,848
Montana-Dakota On October 18, 2023, Montana-Dakota amended and restated its revolving credit agreement to increase the borrowing capacity to $200.0 million and extend the maturity date to October 18, 2028. Montana-Dakota's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The credit agreement contains customary covenants and provisions, including covenants of Montana-Dakota not to permit, as of the end of any fiscal quarter, the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent. Other covenants include limitations on the sale of certain assets and on the making of certain loans and investments.
Montana-Dakota's ratio of total debt to total capitalization at December 31, 2023, was 51 percent.
MDU Resources Group, Inc. Form 10-K 93
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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 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.
Cascade's ratio of total debt to total capitalization at December 31, 2023, was 54 percent.
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 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.
Intermountain's ratio of total debt to total capitalization at December 31, 2023, was 57 percent.
Centennial On June 9, 2023, Centennial repaid the full balances outstanding on all its long-term senior note debt, which aggregated $455.0 million.
MDU Resources Group, Inc. On May 31, 2023, the Company entered into a $200.0 million revolving credit agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2028. Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings. The credit agreement contains customary covenants and provisions, including a covenant of the Company not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments.
On May 31, 2023, the Company entered into a $375.0 million term loan agreement with a SOFR-based variable interest rate and a maturity date of May 31, 2025. On November 15, 2023, the Company paid down $185.0 million of this term loan. 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.
WBI Energy Transmission WBI Energy Transmission has a $350.0 million uncommitted note purchase and private shelf agreement with an expiration date of December 22, 2025. WBI Energy Transmission had $235.0 million of notes outstanding at December 31, 2023, which reduced the remaining capacity under this uncommitted private shelf agreement to $115.0 million. This agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include a limitation on priority debt, restrictions on the sale of certain assets and the making of certain investments.
WBI Energy Transmission's ratio of total debt to total capitalization at December 31, 2023, was 41 percent.
Schedule of Debt Maturities Long-term debt maturities, which excludes unamortized debt issuance costs and discount, for the five years and thereafter following December 31, 2023, were as follows:
2024 2025 2026 2027 2028 Thereafter
(In thousands)
Long-term debt maturities $ 61,319 $ 347,700 $ 140,700 $ 66,800 $ 219,900 $ 1,468,161
94 MDU Resources Group, Inc. Form 10-K
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Note 11 - Leases
Most of the leases the Company enters into are for equipment, buildings, easements and vehicles as part of their ongoing operations. The Company also leases certain equipment to third parties through its utility and construction services businesses. The Company determines if an arrangement contains a lease at inception of a contract and accounts for all leases in accordance with ASC 842 - Leases.
The recognition of leases requires the Company to make estimates and assumptions that affect the lease classification and the assets and liabilities recorded. The accuracy of lease assets and liabilities reported on the Consolidated Financial Statements depends on, among other things, management's estimates of interest rates used to discount the lease assets and liabilities to their present value, as well as the lease terms based on the unique facts and circumstances of each lease.
Lessee accounting
The leases the Company has entered into as part of its ongoing operations are considered operating leases and are recognized on the Consolidated Balance Sheets as operating lease right-of-use assets, current operating lease liabilities and noncurrent liabilities - operating lease liabilities. The corresponding lease costs are included in operation and maintenance expense on the Consolidated Statements of Income.
Generally, the leases for vehicles and equipment have a term of five years or less and buildings and easements have a longer term of up to 35 years or more. To date, the Company does not have any residual value guarantee amounts probable of being owed to a lessor, financing leases or material agreements with related parties.
The following tables provide information on the Company's operating leases at and for the years ended December 31:
2023 2022 2021
(In thousands)
Lease costs:
Short-term lease cost $ 101,610 $ 104,447 $ 79,433
Operating lease cost 29,257 27,016 24,708
Variable lease cost 1,891 1,641 1,431
$ 132,758 $ 133,104 $ 105,572
2023 2022 2021
(Dollars in thousands)
Weighted average remaining lease term 3.20 years 3.17 years 3.27 years
Weighted average discount rate 4.92 % 4.04 % 3.48 %
Cash paid for amounts included in the measurement of lease liabilities
$ 29,678 $ 26,572 $ 21,575
The reconciliation of future undiscounted cash flows to operating lease liabilities presented on the Consolidated Balance Sheet at December 31, 2023, was as follows:
(In thousands)
2024 $ 25,916
2025 17,573
2026 11,143
2027 6,555
2028 3,805
Thereafter 25,724
Total 90,716
Less discount 16,187
Total operating lease liabilities $ 74,529
Lessor accounting
The Company leases certain equipment to third parties through its utility and construction services businesses, which are considered short-term operating leases with terms of less than 12 months. The Company recognized revenue from operating leases of $46.0 million, $47.9 million and $50.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. At December 31, 2023, the Company had $9.4 million of lease receivables with a majority due within 12 months or less.
MDU Resources Group, Inc. Form 10-K 95
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Note 12 - Asset Retirement Obligations
The Company records obligations related to retirement costs of natural gas distribution lines, natural gas transmission lines, natural gas storage wells, decommissioning of certain electric generating facilities, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other obligations as asset retirement obligations.
A reconciliation of the Company's liability, which the current portion is included in other accrued liabilities on the Consolidated Balance Sheets, for the years ended December 31 was as follows:
2023 2022
(In thousands)
Balance at beginning of year $ 373,147 $ 435,280
Liabilities incurred 533 1,315
Liabilities settled (6,633) (7,529)
Accretion expense* 18,894 21,773
Revisions in estimates (787) (77,692)
Balance at end of year $ 385,154 $ 373,147
*Includes $18.9 million and $21.8 million in 2023 and 2022, respectively, recorded to regulatory assets.
The 2022 revisions in estimates consist principally of updated asset retirement obligation costs associated with natural gas distribution and transmission lines at the natural gas distribution segment.
The Company believes that largely all expenses related to asset retirement obligations at the Company's regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets. For more information on the Company's regulatory assets and liabilities, see Note 6.
Note 13 - Equity
The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly dividends for 86 consecutive years. For the years ended December 31, 2023, 2022 and 2021, dividends declared on common stock were $.6950, $.8750 and $.8550 per common share, respectively. Dividends on common stock are paid quarterly to the stockholders of record less than 30 days prior to the distribution date. For the years ended December 31, 2023, 2022 and 2021, the dividends declared to common stockholders were $141.5 million, $177.9 million and $173.0 million, respectively.
The declaration and payment of dividends of the Company is at the sole discretion of the board of directors. In addition, the Company's subsidiaries are generally restricted to paying dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.
Certain credit agreements and regulatory limitations of the Company's subsidiaries also contain restrictions on dividend payments. The most restrictive limitation requires the Company's subsidiaries not to permit the ratio of funded debt to capitalization to be greater than 65 percent. Based on this limitation, approximately $1.3 billion of the net assets of the Company's subsidiaries, which represents common stockholders' equity including retained earnings, would be restricted from use for dividend payments at December 31, 2023.
The Company may sell any combination of common stock and debt securities if warranted by market conditions and the Company's capital requirements. Any public offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.
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 for both the twelve months ended December 31, 2023 and 2022.
The K-Plan provides participants the option to invest in the Company's common stock. For the years ended December 31, 2023, 2022 and 2021, the K-Plan purchased shares of common stock on the open market or issued original issue common stock of the Company. At December 31, 2023, there were 7.2 million shares of common stock reserved for original issuance under the K-Plan.
The Company currently has 2.0 million shares of preferred stock authorized to be issued with a $100 par value. At December 31, 2023 and 2022, there were no shares outstanding.
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Note 14 - Stock-Based Compensation
The Company has stock-based compensation plans under which it is currently authorized to grant restricted stock units and other stock awards. As of December 31, 2023, there were 3.0 million remaining shares available to grant under these plans. The Company either purchases shares on the open market or issues new shares of common stock to satisfy the vesting of stock-based awards.
Separation of Knife River
In connection with the completed separation of Knife River through the spinoff, the provisions of the existing compensation plans required adjustments to the number and terms of outstanding employee time-vested restricted stock units and performance share awards to preserve the intrinsic value of the awards immediately prior to the separation. The outstanding awards will continue to vest over the original vesting period, which is generally three years from the grant date. However, the outstanding performance share awards will no longer be subject to performance-based vesting conditions. The number of performance share awards were first adjusted for performance. The combined performance factors were determined based on the performance of the Company as of December 31, 2022. Outstanding awards at the time of the spinoff were converted into awards of the holder’s employer following separation. The Company incurred $204,000 of incremental compensation expense related to the conversion of the restricted stock units, which is being recognized in expense over the remaining service periods of the applicable awards. There was no incremental compensation expense related to the conversion of the performance share awards.
Total stock-based compensation expense (after tax) was $5.7 million, $7.7 million and $10.6 million in 2023, 2022 and 2021, respectively. The Company uses the straight-line amortization method to recognize compensation expense related to restricted stock units, which only has a service condition. The Company recognized compensation expense related to performance awards with market-based performance metrics on a straight-line basis over the requisite service period. As of December 31, 2023, total remaining unrecognized compensation expense related to stock-based compensation was approximately $11.3 million (before income taxes) which will be amortized over a weighted average period of 1.6 years.
Stock awards
Non-employee directors receive shares of common stock in addition to and in lieu of cash payment for directors' fees. There were 50,717 shares with a fair value of $950,000, 40,800 shares with a fair value of $1.2 million and 41,925 shares with a fair value of $1.2 million issued to non-employee directors during the years ended December 31, 2023, 2022 and 2021, respectively.
Restricted stock units
In February 2023, 2022 and 2021, key employees were granted restricted stock units under the long-term performance-based incentive plan authorized by the Company's compensation committee. The compensation committee has the authority to select the recipients of awards, determine the type and size of awards, and establish certain terms and conditions of unit award grants. The shares vest over three years, contingent on continued employment. Compensation expense is recognized over the vesting period. Upon vesting, participants receive dividends that accumulate during the vesting period.
As previously discussed, adjustments were made to the number of restricted stock units to preserve the intrinsic value of the awards in connection with the spinoff of Knife River and outstanding performance share awards were converted to restricted stock units.
Target grants of restricted stock units outstanding at December 31, 2023, were as follows:
Grant Date Performance Period Target Grant of Shares
February 2022 2022-2024 403,088
February 2023/ July 2023 2023-2025 470,212
Historical performance share awards
In February 2022 and 2021 key employees were granted performance share awards under the long-term performance-based incentive plan authorized by the Company's compensation committee. The compensation committee has the authority to select the recipients of awards, determine the type and size of awards, and establish certain terms and conditions of award grants. Upon vesting, participants receive dividends that accumulate during the vesting period. Share awards were generally earned over a three-year vesting period and tied to financial metrics. However, as previously discussed in connection with the spinoff of Knife River, the outstanding performance share awards were converted to restricted stock units. As a result, there were no outstanding performance shares at December 31, 2023.
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Under the market condition for these performance share awards, participants could earn from zero to 200 percent of the apportioned target grant of shares based on the Company's total stockholder return relative to that of the selected peer group. Compensation expense was based on the grant-date fair value as determined by Monte Carlo simulation. The blended volatility term structure ranges were comprised of 50 percent historical volatility and 50 percent implied volatility. Risk-free interest rates were based on U.S. Treasury security rates in effect as of the grant date. Assumptions used for initial grants applicable to the market condition for certain performance shares issued in 2022 and 2021 were:
2022 2021
Weighted average grant-date fair value $36.25 $37.96
Blended volatility range 24.07% - 31.41%
35.37% - 46.35%
Risk-free interest rate range .71% - 1.68%
.02% - 0.20%
Weighted average discounted dividends per share $2.93 $3.16
Under the performance conditions for these performance share awards, participants could earn from zero to 200 percent of the apportioned target grant of shares. The performance conditions were based on the Company's compound annual growth rate in earnings from continuing operations. The weighted average grant-date fair value per share for the performance shares applicable to these performance conditions issued in 2022 and 2021 was $27.73 and $27.35, respectively.
The fair value of the performance shares that vested during the years ended December 31, 2022 and 2021, was $7.6 million and $13.7 million, respectively.
A summary of the status of the restricted stock units and performance share awards for the year ended December 31, 2023, was as follows:
Performance Share Awards
Restricted Stock Units
Number of
Shares Weighted
Average
Grant-Date
Fair Value Number of Shares
Weighted
Average
Grant-Date
Fair Value **
Nonvested at beginning of period 565,545 $ 32.32 188,499 $ 27.54
Granted pre-separation of Knife River
- 432,557 30.42
Adjustments for performance
(114,543) -
Forfeited
(1,858) 30.47 (5,532) 30.43
Non-vested pre-separation of Knife River
449,144 615,524
Adjustments related to the Knife River separation*
(449,144) 562,944
Granted post-separation of Knife River
- 21,159 22.48
Vested shares
- (326,327) 18.68
Nonvested at end of period - 873,300 $ 21.16
*Includes the conversion adjustments to preserve the intrinsic value of the awards and the cancellation of outstanding awards held by employees that transferred to Knife River, which were replaced with awards issued by Knife River as part of the separation.
** Weighted average grant-date fair values post-separation of Knife River reflects the Company's adjusted stock price due to the separation.
98 MDU Resources Group, Inc. Form 10-K
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Note 15 - Accumulated Other Comprehensive Loss
The Company's accumulated other comprehensive loss is comprised of losses on derivative instruments qualifying as hedges, postretirement liability adjustments and gain (loss) on available-for-sale investments.
The after-tax changes in the components of accumulated other comprehensive loss were as follows:
Net
Unrealized
Loss on
Derivative
Instruments
Qualifying
as Hedges Post-
retirement
Liability
Adjustment Net
Unrealized
Gain (Loss) on
Available-
for-sale
Investments Total
Accumulated
Other
Comprehensive
Loss
(In thousands)
At December 31, 2021 $ (538) $ (40,461) $ (5) $ (41,004)
Other comprehensive income (loss) before reclassifications - 12,007 (667) 11,340
Amounts reclassified to accumulated other comprehensive loss from a regulatory asset - (3,265) - (3,265)
Amounts reclassified from accumulated other comprehensive loss 413 1,819 114 2,346
Net current-period other comprehensive income (loss) 413 10,561 (553) 10,421
At December 31, 2022 (125) (29,900) (558) (30,583)
Other comprehensive income (loss) before reclassifications - (646) 173 (473)
Amounts reclassified from accumulated other comprehensive loss 81 242 43 366
Net current-period other comprehensive income (loss) 81 (404) 216 (107)
Amounts reclassified related to the separation of Knife River 44 12,262 - 12,306
At December 31, 2023 $ - $ (18,042) $ (342) $ (18,384)
The following amounts were reclassified out of accumulated other comprehensive loss into net income. The amounts presented in parentheses indicate a decrease to net income on the Consolidated Statements of Income. The reclassifications for the years ended December 31 were as follows:
2023 2022 Location on Consolidated
Statements of Income
(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income $ (96) $ (590) Interest expense
15 177 Income taxes
(81) (413)
Amortization of postretirement liability losses included in net periodic benefit credit (320) (2,416) Other income
78 597 Income taxes
(242) (1,819)
Reclassification adjustment on available-for-sale investments included in net income (54) (145) Other income
11 31 Income taxes
(43) (114)
Total reclassifications $ (366) $ (2,346)
MDU Resources Group, Inc. Form 10-K 99
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Note 16 - Income Taxes
The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows:
2023 2022 2021
(In thousands)
United States $ 539,898 $ 300,529 $ 286,066
Foreign - - -
Income before income taxes from continuing operations $ 539,898 $ 300,529 $ 286,066
Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:
2023 2022 2021
(In thousands)
Current:
Federal $ 50,180 $ 21,337 $ 11,737
State 13,707 7,176 4,414
Foreign - - -
63,887 28,513 16,151
Deferred:
Income taxes:
Federal (5,960) 16,105 19,092
State (601) 4,245 6,546
Investment tax credit - net 2,147 898 1,755
(4,414) 21,248 27,393
Total income tax expense $ 59,473 $ 49,761 $ 43,544
Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:
2023 2022
(In thousands)
Deferred tax assets:
Postretirement $ 28,953 $ 30,228
Environmental compliance 28,873 -
Compensation-related 27,363 19,867
Operating lease liabilities 14,242 13,914
Customer advances 8,312 7,615
Legal and environmental contingencies 4,881 8,265
Other 29,753 24,024
Total deferred tax assets 142,377 103,913
Deferred tax liabilities:
Basis differences on property, plant and equipment 421,212 405,428
Postretirement 39,110 47,340
Purchased gas adjustment 34,618 33,567
Environmental compliance 16,221 -
Operating lease right-of-use-assets 14,116 13,667
Intangible assets 12,756 12,032
Other 62,076 46,593
Total deferred tax liabilities 600,109 558,627
Valuation allowance 816 785
Net deferred income tax liability $ 458,548 $ 455,499
As of December 31, 2023 and 2022, the Company had various state income tax net operating loss carryforwards of $816,000 and $785,000, respectively, and state income tax credit carryforwards, excluding alternative minimum tax credit carryforwards, of $33.7 million and $35.1 million, respectively. The state income tax credit carryforwards are due to expire between 2025 and 2037. Changes in tax regulations or assumptions regarding current and future taxable income could require additional valuation allowances in the future.
100 MDU Resources Group, Inc. Form 10-K
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The following table reconciles the change in the net deferred income tax liability from December 31, 2022, to December 31, 2023, to deferred income tax expense:
(In thousands)
Change in net deferred income tax liability from the preceding table $ 3,049
Excess deferred income tax amortization (8,383)
Deferred taxes associated with other comprehensive loss (46)
Other 966
Deferred income tax expense for the period $ (4,414)
Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference were as follows:
Years ended December 31, 2023 2022 2021
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal statutory rate $ 113,379 21.0 $ 63,111 21.0 $ 60,074 21.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax
11,677 2.2 9,268 3.1 9,971 3.5
Tax-free debt for equity exchange (38,967) (7.2) - - - -
Federal renewable energy credit
(15,175) (2.8) (15,343) (5.1) (13,914) (4.9)
Excess deferred income tax amortization (8,383) (1.6) (9,008) (3.0) (10,295) (3.6)
Other (3,058) (.6) 1,733 .6 (2,292) (.8)
Total income tax expense $ 59,473 11.0 $ 49,761 16.6 $ 43,544 15.2
The Company's effective tax rate for 2023 differs from the U.S. federal statutory rate of 21 percent due primarily to the permanent difference on the gain on the Knife River retained shares due to the tax-free treatment of the disposition of the shares through the debt-for-equity exchange that was completed in November 2023, the impact of credits and deductions provided by law, and excess deferred income tax amortization. The debt-for equity exchange included an exchange of the approximately 10 percent of Knife River retained shares owned by the Company.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state and local jurisdictions. The Company is no longer subject to U.S. federal, non-U.S., state or local income tax examinations by tax authorities for years ending prior to 2020.
For the years ended December 31, 2023, 2022 and 2021, total reserves for uncertain tax positions were not material. The Company recognizes interest and penalties accrued relative to unrecognized tax benefits in income tax expense.
Note 17 - Cash Flow Information
Cash expenditures for interest and income taxes for the years ended December 31 were as follows:
2023 2022 2021
(In thousands)
Interest, net*
$ 120,431 $ 55,240 $ 72,219
Income taxes paid, net** $ 64,484 $ 5,317 $ 36,295
* AFUDC - borrowed was $10.0 million, $2.2 million and $2.8 million for the years ended December 31, 2023, 2022 and 2021, respectively.
**Income taxes paid, including discontinued operations, were $62.5 million, $26.4 million and $70.9 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Noncash investing and financing transactions at December 31 were as follows:
2023 2022 2021
(In thousands)
Property, plant and equipment additions in accounts payable $ 46,622 $ 35,637 $ 41,765
Right-of-use assets obtained in exchange for new operating lease liabilities $ 46,181 $ 39,158 $ 44,490
Debt for equity exchange of retained shares in Knife River
$ 293,239 $ - $ -
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Note 18 - Business Segment Data
The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The Company's operations are located within the United States.
The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states, as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.
The pipeline segment provides natural gas transportation and underground storage services through a regulated pipeline system primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides non-regulated cathodic protection services.
The construction services segment provides a full spectrum of construction services through its electrical and mechanical and transmission and distribution specialty contracting services across the United States. These specialty contracting services are provided to utilities, manufacturing, transportation, commercial, industrial, institutional, renewable and governmental customers. Its electrical and mechanical contracting services include construction and maintenance of electrical and communication wiring and infrastructure, fire suppression systems, and mechanical piping and services. Its transmission and distribution contracting services include construction and maintenance of overhead and underground electrical, gas and communication infrastructure, as well as manufacturing and supplying transmission and distribution line construction equipment and tools.
The Other category includes the activities of Centennial Capital, which, through its subsidiary InterSource Insurance Company, insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the self-insured layers of the insured Company's general liability, automobile liability, pollution liability and other coverages. Centennial Capital also owns certain real and personal property. In addition, the Other category includes certain assets, liabilities and tax adjustments of the holding company primarily associated with corporate functions, as well as the gain on the tax-free exchange of the retained shares in Knife River and costs associated with certain strategic initiatives. Also included are certain general and administrative costs (reflected in operation and maintenance expense) and interest expense, which were previously allocated to the refining business, Fidelity and Knife River and do not meet the criteria for income (loss) from discontinued operations.
Discontinued operations includes Knife River's operations and its associated separation costs and interest on debt facilities repaid in connection with the Knife River separation. For the comparative periods below, Knife River's operations are only reflected through May 2023, whereas 2022 and 2021 include the full year from Knife River's operations. Discontinued operations also includes the supporting activities of Fidelity other than certain general and administrative costs and interest expense as described above.
The information below follows the same accounting policies as described in Note 2. Information on the Company's segments as of December 31 and for the years then ended was as follows:
2023 2022 2021
(In thousands)
External operating revenues:
Regulated operations:
Electric $ 400,901 $ 376,936 $ 349,412
Natural gas distribution 1,287,121 1,273,530 971,640
Pipeline 101,615 85,931 69,940
1,789,637 1,736,397 1,390,992
Non-regulated operations:
Pipeline 13,457 10,764 13,126
Construction services 2,854,246 2,694,623 2,050,234
Other - - 84
2,867,703 2,705,387 2,063,444
Total external operating revenues $ 4,657,340 $ 4,441,784 $ 3,454,436
102 MDU Resources Group, Inc. Form 10-K
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2023 2022 2021
(In thousands)
Intersegment operating revenues:
Regulated operations:
Electric $ 274 $ 137 $ 170
Natural gas distribution 416 274 300
Pipeline 62,211 58,369 58,989
62,901 58,780 59,459
Non-regulated operations:
Pipeline 329 515 481
Construction services 143 4,627 1,403
Other 7,941 5,840 4,522
8,413 10,982 6,406
Total Intersegment operating revenues $ 71,314 $ 69,762 $ 65,865
Depreciation and amortization:
Electric $ 64,253 $ 67,802 $ 66,750
Natural gas distribution 95,300 89,466 86,065
Pipeline 26,811 26,857 20,569
Construction services 23,148 21,468 20,270
Other 4,086 4,435 4,586
Total depreciation and amortization
$ 213,598 $ 210,028 $ 198,240
Operating income (loss):
Electric $ 92,789 $ 79,655 $ 66,335
Natural gas distribution 92,181 91,889 89,173
Pipeline 69,162 55,466 48,078
Construction services 190,541 164,644 145,754
Other (18,695) (21,655) (18,289)
Total operating income $ 425,978 $ 369,999 $ 331,051
Interest expense:
Electric $ 28,064 $ 28,526 $ 26,712
Natural gas distribution 57,601 42,126 37,265
Pipeline 13,270 10,102 6,705
Construction services 10,057 165 (130)
Other 18,964 415 260
Intersegment eliminations (13,648) (636) (103)
Total interest expense $ 114,308 $ 80,698 $ 70,709
Income tax expense (benefit):
Electric $ (1,019) $ (5,420) $ (7,626)
Natural gas distribution 6,927 7,805 8,366
Pipeline 12,409 10,522 9,672
Construction services 46,968 42,298 36,322
Other (5,812) (5,444) (3,190)
Total income tax expense $ 59,473 $ 49,761 $ 43,544
Net income (loss):
Regulated operations:
Electric $ 71,559 $ 57,077 $ 51,906
Natural gas distribution 48,520 45,171 51,596
Pipeline 46,233 36,253 39,796
166,312 138,501 143,298
MDU Resources Group, Inc. Form 10-K 103
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2023 2022 2021
(In thousands)
Non-regulated operations:
Pipeline 1,142 (59) 1,327
Construction services 142,444 129,460 112,176
Other 170,527 (17,134) (14,279)
314,113 112,267 99,224
Income from continuing operations 480,425 250,768 242,522
Discontinued operations, net of tax (65,718) 116,721 135,609
Net income $ 414,707 $ 367,489 $ 378,131
Capital expenditures:
Electric $ 109,805 $ 133,970 $ 82,427
Natural gas distribution 274,836 240,064 170,411
Pipeline 115,903 61,923 234,803
Construction services 35,096 36,413 29,140
Other (2,825) 2,272 1,501
Total capital expenditures (a) $ 532,815 $ 474,642 $ 518,282
Assets:
Electric (b) $ 1,955,644 $ 1,856,258 $ 1,810,695
Natural gas distribution (b) 3,532,142 3,214,452 2,929,519
Pipeline 1,045,704 961,893 913,945
Construction services 1,106,570 1,126,323 845,262
Other (c) 193,099 2,501,855 2,411,014
Total assets $ 7,833,159 $ 9,660,781 $ 8,910,435
Property, plant and equipment:
Electric (b) $ 2,369,039 $ 2,276,613 $ 2,295,646
Natural gas distribution (b) 3,462,187 3,208,059 3,015,164
Pipeline 1,218,387 1,108,141 1,051,868
Construction services 259,849 245,111 225,758
Other 31,654 36,705 36,717
Less accumulated depreciation and amortization
2,220,206 2,098,298 2,119,074
Net property, plant and equipment $ 5,120,910 $ 4,776,331 $ 4,506,079
(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)Includes allocations of common utility property.
(c)Includes assets of discontinued operations in 2022 and 2021 and assets not directly assignable to a business (i.e. cash, cash equivalents and restricted cash, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).
A reconciliation of reportable segment operating revenues and assets to consolidated operating revenues and assets is as follows:
2023 2022 2021
(In thousands)
Operating revenues reconciliation:
Total reportable segment operating revenues $ 4,720,713 $ 4,505,706 $ 3,515,695
Other revenue 7,941 5,840 4,606
Elimination of intersegment operating revenues (71,314) (69,762) (65,865)
Total consolidated operating revenues $ 4,657,340 $ 4,441,784 $ 3,454,436
Asset reconciliation:
Total reportable segment assets $ 7,685,794 $ 7,205,711 $ 6,535,988
Other assets 726,600 3,639,582 3,366,531
Elimination of intersegment receivables (579,235) (1,184,512) (992,084)
Total consolidated assets $ 7,833,159 $ 9,660,781 $ 8,910,435
104 MDU Resources Group, Inc. Form 10-K
Index
Part II
Note 19 - Employee Benefit Plans
Pension and other postretirement benefit plans
The Company has noncontributory qualified defined benefit pension plans and other postretirement benefit plans for certain eligible employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.
Prior to 2013, defined benefit pension plan benefits and accruals for all nonunion and certain union plans were frozen and on June 30, 2015, the remaining union plan was frozen. These employees were eligible to receive additional defined contribution plan benefits.
Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees who had attained age 55 with 10 years of continuous service by December 31, 2010, were provided the option to choose between a pre-65 comprehensive medical plan coupled with a Medicare supplement or a specified company funded Retiree Reimbursement Account, regardless of when they retire. All other eligible employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire to be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, will not be eligible for retiree medical benefits at certain of the Company's businesses.
In 2012, the Company modified health care coverage for certain retirees. Effective January 1, 2013, post-65 coverage was replaced by a fixed-dollar subsidy for retirees and spouses to be used to purchase individual insurance through a healthcare exchange.
In connection with the previously discussed separation of Knife River on May 31, 2023, Knife River's pension plan, including the associated assets and liabilities, was transferred to Knife River and therefore is no longer reflected as part of the Company. Also in connection with the separation, a remeasurement of the Company's postretirement plan and the Company's unfunded, non-qualified defined benefit plan were performed and the applicable liabilities from the plans relating to transferring employees were transferred to Knife River.
Changes in benefit obligation and plan assets and amounts recognized in the Consolidated Balance Sheets at December 31 were as follows:
Pension Benefits Other
Postretirement Benefits
2023 2022 2023 2022
Change in benefit obligation: (In thousands)
Benefit obligation at beginning of year $ 278,286 $ 367,134 $ 40,315 $ 53,981
Service cost - - 534 894
Interest cost 13,521 9,396 1,956 1,383
Plan participants' contributions - - 479 566
Actuarial loss/(gain)
5,395 (76,130) (215) (13,083)
Benefits paid (21,616) (22,114) (3,479) (3,426)
Benefit obligation at end of year 275,586 278,286 39,590 40,315
Change in net plan assets:
Fair value of plan assets at beginning of year 242,031 333,764 76,640 99,844
Actual return on plan assets 20,576 (69,619) 5,518 (20,419)
Employer contribution 7,567 - 76 75
Plan participants' contributions - - 479 566
Benefits paid (21,616) (22,114) (3,479) (3,426)
Fair value of net plan assets at end of year 248,558 242,031 79,234 76,640
Funded status - (under) over $ (27,028) $ (36,255) $ 39,644 $ 36,325
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent assets - other $ - $ - $ 39,644 $ 36,325
Noncurrent liabilities - other 27,028 36,255 - -
Benefit obligation (liabilities) assets - net amount recognized $ (27,028) $ (36,255) $ 39,644 $ 36,325
Amounts recognized in accumulated other comprehensive loss:
Actuarial loss (gain) $ 32,273 $ 32,378 $ (3,515) $ (2,923)
Prior service credit - - (115) (289)
Total $ 32,273 $ 32,378 $ (3,630) $ (3,212)
Amounts recognized in regulatory assets or liabilities:
Actuarial loss (gain) $ 140,232 $ 141,207 $ (1,146) $ (1,439)
Prior service credit - - (2,619) (3,796)
Total $ 140,232 $ 141,207 $ (3,765) $ (5,235)
MDU Resources Group, Inc. Form 10-K 105
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Part II
Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from, plan assets. Amounts related to regulated operations are recorded as regulatory assets or liabilities and are expected to be reflected in rates charged to customers over time. For more information on regulatory assets and liabilities, see Note 6.
In 2023, the actuarial loss recognized in the benefit obligation was primarily the result of a decrease in the discount rate. In 2022, the actuarial gain recognized in the benefit obligation was primarily the result of an increase in the discount rate. For more information on the discount rates, see the table below. Unrecognized pension actuarial gains and losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average life expectancy of plan participants for frozen plans. The market-related value of assets is determined using a five-year average of assets.
The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for these plans at December 31 were as follows:
2023 2022
(In thousands)
Projected benefit obligation $ 275,586 $ 278,286
Accumulated benefit obligation $ 275,586 $ 278,286
Fair value of plan assets $ 248,558 $ 242,031
The components of net periodic benefit cost (credit), other than the service cost component, are included in other income on the Consolidated Statements of Income. Prior service credit is amortized on a straight-line basis over the average remaining service period of active participants. These components related to the Company's pension and other postretirement benefit plans for the years ended December 31 were as follows:
Pension Benefits Other
Postretirement Benefits
2023 2022 2021 2023 2022 2021
Components of net periodic benefit credit: (In thousands)
Service cost $ - $ - $ - $ 534 $ 894 $ 1,033
Interest cost 13,521 9,396 8,767 1,956 1,383 1,370
Expected return on assets (17,194) (17,482) (17,548) (5,361) (5,277) (5,079)
Amortization of prior service credit
- - - (1,318) (1,318) (1,318)
Recognized net actuarial loss (gain) 3,093 5,826 7,046 (504) (570) (111)
Net periodic benefit credit, including amount capitalized (580) (2,260) (1,735) (4,693) (4,888) (4,105)
Less amount capitalized - - - 107 175 150
Net periodic benefit cost credit (580) (2,260) (1,735) (4,800) (5,063) (4,255)
Other changes in plan assets and benefit obligations recognized in accumulated comprehensive loss:
Net (gain) loss 187 2,369 (265) (604) (4,141) (2,811)
Amortization of actuarial (loss) gain
(292) (1,310) (1,286) 108 (281) (135)
Amortization of prior service credit - - - 78 125 100
Reclassification of postretirement liability adjustment from regulatory asset - 5,343 - - (992) -
Total recognized in accumulated other comprehensive loss
(105) 6,402 (1,551) (418) (5,289) (2,846)
Other changes in plan assets and benefit obligations recognized in regulatory assets or liabilities:
Net (gain) loss 1,826 9,757 (5,116) (107) 11,920 (6,292)
Amortization of actuarial (loss) gain
(2,801) (5,373) (6,731) 304 500 110
Amortization of prior service credit
- - - 1,273 1,273 1,298
Reclassification of postretirement liability adjustment from regulatory asset - (5,343) - - 992 -
Total recognized in regulatory assets or liabilities
(975) (959) (11,847) 1,470 14,685 (4,884)
Total recognized in net periodic benefit credit, accumulated other comprehensive loss and regulatory assets or liabilities $ (1,660) $ 3,183 $ (15,133) $ (3,748) $ 4,333 $ (11,985)
106 MDU Resources Group, Inc. Form 10-K
Index
Part II
Weighted average assumptions used to determine benefit obligations at December 31 were as follows:
Pension Benefits Other
Postretirement Benefits
2023 2022 2023 2022
Discount rate 4.84 % 5.06 % 4.85 % 5.07 %
Expected return on plan assets 6.50 % 6.50 % 6.00 % 6.00 %
Weighted average assumptions used to determine net periodic benefit cost (credit) for the years ended December 31 were as follows:
Pension Benefits Other
Postretirement Benefits
2023 2022 2023 2022
Discount rate 5.06 % 2.64 % 5.07 % 2.65 %
Expected return on plan assets 6.50 % 6.00 % 6.00 % 5.50 %
The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2023, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40 percent to 50 percent equity securities and 50 percent to 60 percent fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 10 percent to 20 percent equity securities and 80 percent to 90 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.
Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:
2023 2022
Health care trend rate assumed for next year 6.5 % 6.5 %
Health care cost trend rate - ultimate 4.5 % 4.5 %
Year in which ultimate trend rate achieved 2033 2032
The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of retirement. The Company contributes a flat dollar amount to the monthly premiums which is updated annually on January 1.
The Company expects to contribute to its defined benefit pension plans in 2024 the minimum funding requirement of $3.3 million. The Company expects to contribute approximately $22,000 to its postretirement benefit plans in 2024.
The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies at December 31, 2023, are as follows:
Years Pension
Benefits Other
Postretirement Benefits Expected
Medicare
Part D Subsidy
(In thousands)
2024 $ 22,050 $ 3,498 $ 50
2025 21,980 3,473 44
2026 21,810 3,359 39
2027 21,660 3,265 35
2028 21,320 3,171 29
2029-2033 99,970 14,580 94
Outside investment managers manage the Company's pension and postretirement assets. The Company's investment policy with respect to pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of funds in cash equivalents, fixed-income securities and equity securities. The guidelines prohibit investment in commodities and futures contracts, equity private placement, employer securities, leveraged or derivative securities, options, direct real estate investments, precious metals, venture capital and limited partnerships. The guidelines also prohibit short selling and margin transactions. The Company's practice is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy.
MDU Resources Group, Inc. Form 10-K 107
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Part II
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The fair value ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The estimated fair values of the Company's pension plans' assets are determined using the market approach.
The carrying value of the pension plans' Level 2 cash equivalents approximates fair value and is determined using observable inputs in active markets or the net asset value of shares held at year end, which is determined using other observable inputs including pricing from outside sources.
The estimated fair value of the pension plans' Level 1 and Level 2 equity securities are based on the closing price reported on the active market on which the individual securities are traded or other known sources including pricing from outside sources. The estimated fair value of the pension plans' Level 1 and Level 2 collective and mutual funds are based on the net asset value of shares held at year end, based on either published market quotations on active markets or other known sources including pricing from outside sources. The estimated fair value of the pension plans' Level 2 corporate and municipal bonds is determined using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, future cash flows and other reference data. The estimated fair value of the pension plans' Level 1 U.S. Government securities are valued based on quoted prices on an active market. The estimated fair value of the pension plans' Level 2 U.S. Government securities are valued mainly using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, to be announced prices, future cash flows and other reference data. The estimated fair value of the pension plans' Level 2 pooled separate accounts are determined using observable inputs in active markets or the net asset value of shares held at year end, or other observable inputs. Some of these securities are valued using pricing from outside sources.
All investments measured at net asset value in the tables that follow are invested in commingled funds, separate accounts or common collective trusts which do not have publicly quoted prices. The fair value of the commingled funds, separate accounts and common collective trusts are determined based on the net asset value of the underlying investments. The fair value of the underlying investments held by the commingled funds, separate accounts and common collective trusts is generally based on quoted prices in active markets.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.
The fair value of the Company's pension plans' assets (excluding cash) by class were as follows:
Fair Value Measurements
at December 31, 2023, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2023
(In thousands)
Assets:
Cash equivalents $ - $ 7,197 $ - $ 7,197
Equity securities:
U.S. companies (2) - - (2)
Collective and mutual funds (a) 84,761 88,219 - 172,980
U.S. Government securities 30,162 33,141 - 63,303
Investments measured at net asset value (b)
- - - 5,080
Total assets measured at fair value $ 114,921 $ 128,557 $ - $ 248,558
(a)Collective and mutual funds invest approximately 51 percent in corporate bonds, 15 percent in common stock of international companies, 11 percent in common stock of large-cap and mid-cap U.S. companies, 7 percent cash and cash equivalents, 7 percent in U.S. Government securities and 9 percent in other investments.
(b)In accordance with ASC 820 - Fair Value Measurements, certain investments that were measured at net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the Consolidated Balance Sheets.
108 MDU Resources Group, Inc. Form 10-K
Index
Part II
Fair Value Measurements
at December 31, 2022, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2022
(In thousands)
Assets:
Cash equivalents $ - $ 7,311 $ - $ 7,311
Equity securities:
U.S. companies 6,611 - - 6,611
International companies - 418 - 418
Collective and mutual funds (a) 108,343 29,863 - 138,206
Corporate bonds - 72,809 - 72,809
Municipal bonds - 5,283 - 5,283
U.S. Government securities 2,724 788 - 3,512
Pooled separate accounts (b) - 2,904 - 2,904
Investments measured at net asset value (c) - - - 4,977
Total assets measured at fair value $ 117,678 $ 119,376 $ - $ 242,031
(a)Collective and mutual funds invest approximately 29 percent in corporate bonds, 24 percent in common stock of large-cap U.S. companies, 16 percent in common stock of international companies, 7 percent cash and cash equivalents, 7 percent in U.S. Government securities and 17 percent in other investments.
(b)Pooled separate accounts are invested 100 percent in cash and cash equivalents.
(c)In accordance with ASC 820 - Fair Value Measurements, certain investments that were measured at net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the Consolidated Balance Sheets.
The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.
The estimated fair value of the other postretirement benefit plans' Level 2 cash equivalents is valued at the net asset value of shares held at year end, based on published market quotations on active markets, or using other known sources including pricing from outside sources. The estimated fair value of the other postretirement benefit plans' Level 1 and Level 2 equity securities is based on the closing price reported on the active market on which the individual securities are traded or other known sources including pricing from outside sources. The estimated fair value of the other postretirement benefit plans' Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.
The fair value of the Company's other postretirement benefit plans' assets (excluding cash) by asset class were as follows:
Fair Value Measurements
at December 31, 2023, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2023
(In thousands)
Assets:
Cash equivalents $ - $ 4,562 $ - $ 4,562
Equity securities:
U.S. companies 2,369 - - 2,369
Insurance contract (a)
- 72,303 - 72,303
Total assets measured at fair value $ 2,369 $ 76,865 $ - $ 79,234
(a)The insurance contract invests approximately 60 percent in corporate bonds, 16 percent in common stock of large-cap U.S. companies, 15 percent in U.S. Government securities, 5 percent in common stock of small-cap U.S. companies and 4 percent in other investments.
MDU Resources Group, Inc. Form 10-K 109
Index
Part II
Fair Value Measurements
at December 31, 2022, Using
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at December 31, 2022
(In thousands)
Assets:
Cash equivalents $ - $ 4,213 $ - $ 4,213
Equity securities:
U.S. companies 2,583 - - 2,583
Collective and mutual funds (a) 5 5 - 10
Insurance contract (b) - 69,834 - 69,834
Total assets measured at fair value $ 2,588 $ 74,052 $ - $ 76,640
(a)Collective and mutual funds invest approximately 29 percent in corporate bonds, 24 percent in common stock of large-cap U.S. companies, 16 percent in common stock of international companies, 7 percent in cash and cash equivalents, 7 percent in U.S. Government securities and 17 percent in other investments.
(b)The insurance contract invests approximately 69 percent in corporate bonds, 14 percent in common stock of large-cap U.S. companies, 13 percent in U.S. Government securities and 4 percent in common stock of small-cap U.S. companies.
Nonqualified benefit plans
In addition to the qualified defined benefit pension plans reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified defined benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or, upon death, to their beneficiaries for a 15-year period. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated benefit increases. Vesting for participants not fully vested was retained.
The projected benefit obligation and accumulated benefit obligation for these plans at December 31 were as follows:
2023 2022
(In thousands)
Projected benefit obligation $ 57,033 $ 58,683
Accumulated benefit obligation $ 57,033 $ 58,683
The components of net periodic benefit cost are included in other income on the Consolidated Statements of Income. These components related to the Company's nonqualified defined benefit plans for the years ended December 31 were as follows:
2023 2022 2021
(In thousands)
Components of net periodic benefit cost:
Interest cost 2,740 1,681 1,505
Recognized net actuarial loss 273 911 942
Net periodic benefit cost $ 3,013 $ 2,592 $ 2,447
Weighted average assumptions used at December 31 were as follows:
2023 2022
Benefit obligation discount rate 4.73 % 4.97 %
Benefit obligation rate of compensation increase N/A N/A
Net periodic benefit cost discount rate 4.97 % 2.40 %
Net periodic benefit cost rate of compensation increase N/A N/A
The amount of future benefit payments for the unfunded, nonqualified defined benefit plans at December 31, 2023, are expected to aggregate as follows:
2024 2025 2026 2027 2028 2029-2033
(In thousands)
Nonqualified benefits $ 5,584 $ 5,726 $ 5,795 $ 5,807 $ 5,481 $ 21,962
110 MDU Resources Group, Inc. Form 10-K
Index
Part II
In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. In 2020, the plan was frozen to new participants and no new Company contributions will be made to the plan after December 31, 2020. Vesting for participants not fully vested was retained. A new nonqualified defined contribution plan was adopted in 2020, effective January 1, 2021, to replace the plan originally established in 2012 with similar provisions. Expenses incurred under these plans for 2023, 2022 and 2021 were $5.5 million, $2.2 million and $1.5 million, respectively.
The amount of investments that the Company anticipates using to satisfy obligations under these plans at December 31 was as follows:
2023 2022
(In thousands)
Investments
Insurance contracts* $ 66,283 $ 77,958
Life insurance** 31,303 31,214
Other 6,409 4,913
Total investments $ 103,995 $ 114,085
*For more information on the insurance contracts, see Note 9.
**Investments of life insurance are carried on plan participants (payable upon the employee's death).
Defined contribution plans
The Company sponsors a defined contribution plan for eligible employees and the costs incurred under this plan were $23.2 million in 2023, $18.7 million in 2022 and $18.8 million in 2021.
Multiemployer plans
The Company contributes to a number of MEPPs under the terms of collective-bargaining agreements that cover its union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:
•Assets contributed to the MEPP by one employer may be used to provide benefits to employees of other participating employers
•If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers
•If the Company chooses to stop participating in some of its MEPPs, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability
The Company's participation in these plans is outlined in the following table. Unless otherwise noted, the most recent Pension Protection Act zone status available in 2023 and 2022 is for the plan's year-end at December 31, 2022, and December 31, 2021, respectively. The zone status is based on information that the Company received from the plan and is certified by the plan's actuary. Among other factors, plans in the red zone are generally less than 65 percent funded, plans in the yellow zone are between 65 percent and 80 percent funded, and plans in the green zone are at least 80 percent funded.
MDU Resources Group, Inc. Form 10-K 111
Index
Part II
EIN/Pension Plan Number Pension Protection Act Zone Status FIP/RP Status Pending/Implemented Contributions Surcharge Imposed Expiration Date
of Collective
Bargaining
Agreement
Pension Fund 2023 2022 2023 2022 2021
(In thousands)
Edison Pension Plan 936061681-001
Green Green No $ 16,957 $ 18,750 $ 18,331 No 12/31/2026
IBEW Local 212 Pension Trust 316127280-001
Green as of 4/30/2022
Green as of 4/30/2021
No 1,350 1,622 1,733 No 6/1/2025
IBEW Local 357 Pension Plan A 886023284-001
Green Green No 18,936 12,876 6,485 No 5/31/2024
IBEW Local 82 Pension Plan 316127268-001
Green as of 6/30/2023
Green as of 6/30/2022
No 2,149 1,854 1,353 No 12/6/2026
IBEW Local 683 Pension Fund Pension Plan 341442087-001
Green Green No 3,986 3,362 1,238 No 5/26/2024
Idaho Plumbers and Pipefitters Pension Plan 826010346-001
Green as of 5/31/2023
Green as of 5/31/2022
No 1,690 1,613 1,528 No 3/31/2027
National Electrical Benefit Fund 530181657-001
Green Green No 19,040 18,060 14,361 No 12/31/2023- 12/27/2027
*
Pension and Retirement Plan of Plumbers and Pipefitters Local 525 886003864-001
Green as of 6/30/2022
Green as of 6/30/2022
No 8,020 6,304 4,345 No 9/30/2024
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV 956052257-001
Green Green No 3,631 3,400 2,615 No 6/30/2024
Other funds 21,289 20,437 17,930
Total contributions $ 97,048 $ 88,278 $ 69,919
*Plan includes contributions required by collective bargaining agreements which have expired but contain provisions automatically renewing their terms in the absence of a subsequent negotiated agreement.
The Company was listed in the plans' Forms 5500 as providing more than 5 percent of the total contributions for the following plans and plan years:
Pension Fund Year Contributions to Plan Exceeded More Than 5 Percent
of Total Contributions (as of December 31 of the Plan's Year-End)
Edison Pension Plan 2022 and 2021
Eighth District Electrical Pension Fund 2022
Electrical Workers Local No. 26 Pension Fund 2022
IBEW Local 82 Pension Plan 2022 and 2021
IBEW Local 124 Pension Trust Fund 2022 and 2021
IBEW Local 212 Pension Trust Fund 2022 and 2021
IBEW Local 357 Pension Plan A 2021
IBEW Local 648 Pension Plan 2022 and 2021
IBEW Local 683 Pension Fund Pension Plan 2022 and 2021
Idaho Plumbers and Pipefitters Pension Plan 2022 and 2021
National Electrical Benefit Fund 2022
Pension and Retirement Plan of Plumbers and Pipefitters Local 525 2022 and 2021
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV 2022
Western States Insulators and Allied Workers' Pension Plan 2022
The Company also contributes to a number of multiemployer other postretirement plans under the terms of collective-bargaining agreements that cover its union-represented employees. These plans provide benefits such as health insurance, disability insurance and life insurance to retired union employees. Many of the multiemployer other postretirement plans are combined with active multiemployer health and welfare plans. The Company's total contributions to its multiemployer other postretirement plans, which also includes contributions to active multiemployer health and welfare plans, were $86.6 million, $79.1 million and $64.4 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Amounts contributed in 2023, 2022 and 2021 to defined contribution multiemployer plans were $73.3 million, $67.6 million and $54.6 million, respectively.
112 MDU Resources Group, Inc. Form 10-K
Index
Part II
Note 20 - Jointly Owned Facilities
The consolidated financial statements include the Company's ownership interests in three coal-fired electric generating facilities (Big Stone Station, Coyote Station and Wygen III) and two major transmission lines (BSSE and JETx). Each owner of the jointly owned facilities is responsible for financing its investment. The Company's share of the jointly owned facilities operating expenses was reflected in the appropriate categories of operating expenses (electric fuel and purchased power; operation and maintenance; and taxes, other than income) in the Consolidated Statements of Income.
At December 31, the Company's share of the cost of utility plant in service, construction work in progress and related accumulated depreciation for the jointly owned facilities was as follows:
Ownership Percentage 2023 2022
(In thousands)
Big Stone Station: 22.7 %
Utility plant in service $ 159,437 $ 157,699
Construction work in progress 197 231
Less accumulated depreciation 52,264 48,590
$ 107,370 $ 109,340
BSSE: 50.0 %
Utility plant in service $ 107,260 $ 107,260
Construction work in progress - -
Less accumulated depreciation 8,111 6,182
$ 99,149 $ 101,078
Coyote Station: 25.0 %
Utility plant in service $ 160,208 $ 158,274
Construction work in progress 159 1,807
Less accumulated depreciation 113,187 111,203
$ 47,180 $ 48,878
JETx:
50.0 %
Utility plant in service $ - $ -
Construction work in progress 1,372 -
Less accumulated depreciation - -
$ 1,372 $ -
Wygen III: 25.0 %
Utility plant in service $ 66,852 $ 66,238
Construction work in progress 127 273
Less accumulated depreciation 13,728 12,477
$ 53,251 $ 54,034
MDU Resources Group, Inc. Form 10-K 113
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Note 21 - Regulatory Matters
The Company regularly reviews the need for electric and natural gas rate changes in each of the jurisdictions in which service is provided. The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed by regulators. Certain regulatory proceedings and cases may also contain recurring mechanisms that can have an annual true-up. Examples of these recurring mechanisms include: infrastructure riders, transmission trackers, renewable resource cost adjustment riders, as well as weather normalization and decoupling mechanisms. The following paragraphs summarize the Company's significant open regulatory proceedings and cases by jurisdiction. The Company is unable to predict the ultimate outcome of these matters, the timing of final decisions of the various regulators and courts, or the effect on the Company's results of operations, financial position or cash flows.
NDPSC
On November 1, 2023, Montana-Dakota filed a request with the NDPSC for a natural gas general rate increase of approximately $11.6 million annually or 7.5 percent above current rates. The requested increase is primarily to recover investments in system upgrades and pipeline replacement projects enhancing the reliability, safety and integrity of the natural gas system, as well as increased costs to operate and maintain that system. On December 13, 2023, the NDPSC approved an interim rate increase of approximately $10.1 million annually or 6.5 percent above current rates, subject to refund, for service rendered on and after January 1, 2024. This matter is pending before the NDPSC.
Montana-Dakota has a renewable resource cost adjustment rate tariff that allows for annual adjustments for recent projected capital costs and related expenses for projects determined to be recoverable under the tariff. On October 31, 2023, Montana-Dakota filed an annual update to its renewable resource cost adjustment requesting to recover a revenue requirement of approximately $21.0 million annually, which was revised to $19.5 million on January 29, 2024. The update reflects an increase of approximately $4.2 million from the revenues currently included in rates. The NDPSC approved the renewable resource cost adjustment on February 7, 2024, with rates effective March 1, 2024.
SDPUC
On August 15, 2023, Montana-Dakota filed a request with the SDPUC for an electric general rate increase of approximately $3.0 million annually or 17.3 percent above current rates. The requested increase is primarily to recover investments in system upgrades and pipeline replacement projects enhancing the reliability, safety and integrity of the natural gas system, as well as increased costs to operate and maintain that system. On January 26, 2024, Montana-Dakota filed a notice of intent to implement interim rates of $2.7 million annually or 15.4 percent above current rates, which reflects the removal of Heskett Unit 4 due to the project delay caused by unforeseen operational setbacks. The interim rates, subject to refund, will be effective March 1, 2024. This matter is pending before the SDPUC.
On August 15, 2023, Montana-Dakota filed a request with the SDPUC for a natural gas general rate increase of approximately $7.4 million annually or 11.2 percent above current rates. The requested increase is primarily to recover investments and the associated depreciation, operation and maintenance expenses and taxes associated with the increased investment. On January 26, 2024, Montana-Dakota filed a notice of intent to implement interim rates, subject to refund, effective March 1, 2024. This matter is pending before the SDPUC.
FERC
On January 27, 2023, WBI Energy Transmission filed a general rate case with the FERC for increases in its transportation and storage services rates that also includes a Greenhouse Gas Cost Recovery Mechanism for anticipated future costs. In August 2023, the Company reached a rate case settlement agreement with its customers and FERC staff and the agreed-upon rates were placed into effect as of August 1, 2023. The settlement agreement did not include a Greenhouse Gas Cost Recovery Mechanism. On October 17, 2023, the Administrative Law Judge certified the Company's rate case settlement agreement to the FERC for final approval. On November 27, 2023, the request was approved by FERC.
On August 31, 2023, Montana-Dakota filed an update to its transmission formula rate under the MISO tariff for its multi-value project and network upgrade charges for $15.2 million, which was updated to $15.4 million on November 16, 2023. Rates were effective January 1, 2024.
114 MDU Resources Group, Inc. Form 10-K
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Note 22 - Commitments and Contingencies
The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries, which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. Accruals are based on the best information available, but in certain situations management is unable to estimate an amount or range of a reasonably possible loss including, but not limited to when: (1) the damages are unsubstantiated or indeterminate, (2) the proceedings are in the early stages, (3) numerous parties are involved, or (4) the matter involves novel or unsettled legal theories.
At December 31, 2023 and 2022, the Company accrued liabilities which have not been discounted of $22.5 million and $31.9 million, respectively. At December 31, 2023 and 2022, the Company also recorded corresponding insurance receivables of $202,000 and $10.0 million, respectively, and regulatory assets of $21.6 million and $20.9 million, respectively, related to the accrued liabilities. The accruals are for contingencies resulting from litigation and environmental matters. This includes amounts that have been accrued for matters discussed in Environmental matters within this note. The Company will continue to monitor each matter and adjust accruals as might be warranted based on new information and further developments. Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of insurance recoveries, while uncertain, either cannot be estimated or will not have a material effect upon the Company's financial position, results of operations or cash flows. Unless otherwise required by GAAP, legal costs are expensed as they are incurred.
Environmental matters
Manufactured Gas Plant Sites Claims have been made against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors and a similar claim has been made against Montana-Dakota for a site operated by Montana-Dakota and its predecessors. Any accruals related to these claims are reflected in regulatory assets. For more information, see Note 6.
Demand has been made of Montana-Dakota to participate in investigation and remediation of environmental contamination at a site in Missoula, Montana. The site operated as a former manufactured gas plant from approximately 1907 to 1938 when it was converted to a butane-air plant that operated until 1956. Montana-Dakota or its predecessors owned or controlled the site for a period of the time it operated as a manufactured gas plant and Montana-Dakota operated the butane-air plant from 1940 to 1951, at which time it sold the plant. There are no documented wastes or by-products resulting from the mixing or distribution of butane-air gas. Preliminary assessment of a portion of the site provided a recommended remedial alternative for that portion of approximately $560,000. However, the recommended remediation would not address any potential contamination to adjacent parcels that may be impacted from historic operations of the manufactured gas plant. An environmental assessment, which was started in 2020 and is still underway, is estimated to cost approximately $1.8 million. Montana-Dakota and another party agreed to voluntarily investigate and remediate the site and that Montana-Dakota will pay two-thirds of the costs for further investigation and remediation of the site. Montana-Dakota has accrued costs of $610,000 for the remediation and investigation costs, and has incurred costs of $1.0 million as of December 31, 2023. Montana-Dakota received notice from a prior insurance carrier that it will participate in payment of defense costs incurred in relation to the claim. On December 9, 2021, Montana Dakota filed an application with the MTPSC for deferred accounting treatment for costs associated with the investigation and remediation of the site. The MTPSC approved the application for deferred accounting treatment as requested on July 26, 2022.
A claim was made against Cascade for contamination at the Bremerton Gasworks Superfund Site in Bremerton, Washington, which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain impacts requiring further investigation and cleanup. The EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirmed that impacts have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. In April 2010, the Washington DOE issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Current estimates for the cost to complete the remedial investigation and feasibility study are approximately $13.7 million of which $10.6 million has been incurred as of December 31, 2023. Based on the site investigation, preliminary remediation alternative costs were provided by consultants in August 2020. The preliminary information received through the completion of the data report allowed for the projection of possible costs for a variety of site configurations, remedial measures and potential natural resource damage claims of between $13.6 million and $71.5 million. At December 31, 2023, Cascade has accrued $3.2 million for the remedial investigation and feasibility study, as well as $17.5 million for remediation of this site. The accrual for remediation costs will be reviewed and adjusted, if necessary, after the completion of the feasibility study. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs incurred in relation to the environmental remediation of this site. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.
MDU Resources Group, Inc. Form 10-K 115
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A claim was made against Cascade for impacts at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for impacts from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. Other PRPs reached an agreed order and work plan with the Washington DOE for completion of a remedial investigation and feasibility study for the site. A feasibility study prepared for one of the PRPs in March 2018 identifies five cleanup action alternatives for the site with estimated costs ranging from $8.0 million to $20.4 million with a selected preferred alternative having an estimated total cost of $9.3 million. The other PRPs developed a cleanup action plan and completed public review in 2020. The development of the remediation design is underway, with the Pre-Remedial Design Investigation Data Report submitted to Washington Ecology on June 28, 2023. The remedy construction is expected to occur following the approval of the final design. Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, the plant converted to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas. Cascade has recorded an accrual for this site for an amount that is not material.
The Company has received notices from and entered into agreements with certain of its insurance carriers that they will participate in the defense for certain contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, the Company intends to seek recovery of remediation costs through its natural gas rates charged to customers.
Purchase commitments
The Company has entered into various commitments largely consisting of contracts for natural gas and coal supply; purchased power; natural gas transportation and storage; and information technology. Certain of these contracts are subject to variability in volume and price. The commitment terms vary in length, up to 36 years. The commitments under these contracts as of December 31, 2023, were:
2024 2025 2026 2027 2028 Thereafter
(In thousands)
Purchase commitments $ 674,932 $ 298,785 $ 167,915 $ 124,893 $ 119,600 $ 670,311
These commitments were not reflected in the Company's consolidated financial statements. Amounts purchased under various commitments for the years ended December 31, 2023, 2022 and 2021, were $1.0 billion, $870.6 million and $711.9 million, respectively.
Guarantees
Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, insurance deductibles and loss limits, and certain other guarantees. At December 31, 2023, the fixed maximum amounts guaranteed under these agreements aggregated $341.4 million. Certain of the guarantees also have no fixed maximum amounts specified. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate to $80.9 million in 2024; $255.1 million in 2025; $4.1 million in 2026; $1.0 million in 2027; $300,000 in 2028; and $0 thereafter. There were no amounts outstanding under the previously mentioned guarantees at December 31, 2023. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.
The Company and certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At December 31, 2023, the fixed maximum amounts guaranteed under these letters of credit aggregated $33.9 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate to $33.9 million in 2024. There were no amounts outstanding under the previously mentioned letters of credit at December 31, 2023. In the event of default under these letter of credit obligations, the Company or subsidiary guaranteeing the letter of credit would be obligated for reimbursement of payments made under the letter of credit.
In addition, Centennial and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial or MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company were reflected on the Consolidated Balance Sheet at December 31, 2023.
In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At December 31, 2023, approximately $313.0 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.
116 MDU Resources Group, Inc. Form 10-K
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Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary.
Fuel Contract Coyote Station entered into a coal supply agreement with Coyote Creek that provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040. Coal purchased under the coal supply agreement is reflected in inventories on the Consolidated Balance Sheets and is recovered from customers as a component of electric fuel and purchased power.
The coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations, as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.
At December 31, 2023, the Company's exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, was $27.6 million.
Note 23 - Subsequent Events
On January 19, 2024, Cascade made the final $50.0 million repayment on the $150.0 million term loan agreement which Cascade had entered into on January 20, 2023, with a SOFR-based variable interest rate and a maturity date of January 19, 2024.
On January 19, 2024, Intermountain made the final $45.0 million repayment on the $125.0 million term loan agreement which Intermountain had entered into on January 20, 2023, with a SOFR-based variable interest rate and a maturity date of January 19, 2024.
MDU Resources Group, Inc. Form 10-K 117
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Definitions
The following abbreviations and acronyms used in Notes to Consolidated Financial Statements are defined below:
Abbreviation or Acronym
AFUDC Allowance for funds used during construction
ASC FASB Accounting Standards Codification
ASU FASB Accounting Standards Update
Big Stone Station 475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BSSE 345-kV transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota (50 percent ownership)
Cascade Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
Centennial CEHI, LLC, a direct wholly owned subsidiary of the Company, formally known as Centennial Energy Holdings, Inc. prior to the separation of Knife River from the Company. References to Centennial's historical business and operations refer to the business and operations of Centennial Energy Holdings, Inc.
Centennial Capital Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Company MDU Resources Group, Inc.
Coyote Creek Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station 427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
EBITDA Earnings before interest, taxes, depreciation and amortization
EIN Employer Identification Number
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fidelity Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings (previously referred to as the Company's exploration and production segment)
FIP Funding improvement plan
GAAP Accounting principles generally accepted in the United States of America
Great Plains Great Plains Natural Gas Co., a public utility division of Montana-Dakota
IBEW International Brotherhood of Electrical Workers
Intermountain Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC Idaho Public Utilities Commission
IRS Internal Revenue Service
JETx
345-kV transmission line from Jamestown, North Dakota to Ellendale, North Dakota (50 percent ownership)
Knife River Established as Knife River Corporation prior to the separation from the Company, a direct wholly owned subsidiary of Centennial. Knife River refers to Knife River Corporation, during the period prior to separation, now known as "KRC Materials, Inc." Following the separation Knife River refers to Knife River Holding Company, now known as Knife River Corporation.
K-Plan Company's 401(k) Retirement Plan
LIBOR London Inter-bank Offered Rate
MDU Construction Services MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MEPP Multiemployer pension plan
MISO Midcontinent Independent System Operator, Inc., the organization that provides open-access transmission services and monitors the high-voltage transmission system in the Midwest United States and Manitoba, Canada and a southern United States region which includes much of Arkansas, Mississippi and Louisiana
MNPUC Minnesota Public Utilities Commission
Montana-Dakota Montana-Dakota Utilities Co. a direct wholly owned subsidiary of MDU Energy Capital
MTPSC Montana Public Service Commission
MW Megawatt
NDPSC North Dakota Public Service Commission
PRP Potentially Responsible Party
RP Rehabilitation plan
SDPUC South Dakota Public Utilities Commission
118 MDU Resources Group, Inc. Form 10-K
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SEC United States Securities and Exchange Commission
Securities Act Securities Act of 1933, as amended
SOFR Secured Overnight Financing Rate
VIE Variable interest entity
Washington DOE Washington State Department of Ecology
WBI Energy Transmission WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC Washington Utilities and Transportation Commission
Wygen III 100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
MDU Resources Group, Inc. Form 10-K 119
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.
Evaluation of Disclosure Controls and Procedures
The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of the Company's disclosure controls and other procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and the chief financial officer have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.
Changes in Internal Controls
No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the three months ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Annual Report on Internal Control Over Financial Reporting
The information required by this item is included in this Form 10-K at Item 8 - Management's Report on Internal Control Over Financial Reporting.
Attestation Report of the Registered Public Accounting Firm
The information required by this item is included in this Form 10-K at Item 8 - Report of Independent Registered Public Accounting Firm.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
During the three months ended December 31, 2023, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Equity Compensation Plan Information
The following table includes information as of December 31, 2023, with respect to the Company's equity compensation plans:
Plan Category Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by stockholders (1) 873,300 (2) $ - (3) 2,139,336 (4)(5)
Equity compensation plans not approved by stockholders N/A N/A N/A
Total 873,300 $ - 2,139,336
(1) Consists of the Non-Employee Director Long-Term Incentive Compensation Plan and the Long-Term Performance-Based Incentive Plan. For more information, see Note 14.
(2) Consists of restricted stock units.
(3) No weighted average exercise price is shown for the restricted stock units or performance share awards because such awards have no exercise price.
(4) This amount includes 2,047,439 shares available for future issuance under the Long-Term Performance-Based Incentive Plan in connection with grants of restricted stock units, performance units, performance shares or other equity-based awards.
(5) This amount includes 91,897 shares available for future issuance under the Non-Employee Director Long-Term Incentive Compensation Plan.
The remaining information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
Information required by this item about aggregate fees billed to the Company by its principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34), will be included in the Company's Proxy Statement, which is incorporated herein by reference.
MDU Resources Group, Inc. Form 10-K 121
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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) Financial Statements, Financial Statement Schedules and Exhibits
Index to Financial Statements and Financial Statement Schedules
1. Financial Statements
The following consolidated financial statements required under this item are
included under Item 8 - Financial Statements and Supplementary Data.
Page
Consolidated Statements of Income for each of the three years in the period ended December 31, 2023
Consolidated Statements of Comprehensive Income for each of the three years in the period ended December 31, 2023
Consolidated Balance Sheets at December 31, 2023 and 2022
Consolidated Statements of Equity for each of the three years in the period ended December 31, 2023
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2023
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
The following financial statement schedules are included in Part IV of this report. Page
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income for each of the three years in the period ended December 31, 2023
Condensed Balance Sheets at December 31, 2023 and 2022
Condensed Statements of Cash Flows for each of the three years in the period ended December 31, 2023
Notes to Condensed Financial Statements
All other schedules have been omitted because they are not applicable or the required information is included elsewhere in the financial statements or related notes.
3. Exhibits
122 MDU Resources Group, Inc. Form 10-K
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MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income
Years ended December 31, 2023 2022 2021
(In thousands)
Operating revenues $ - $ - $ -
Operating expenses 14,959 4,888 -
Operating loss (14,959) (4,888) -
Realized gain on tax-free exchange of the retained shares in Knife River 186,556 - -
Interest expense 16,099 - -
Income (loss) before income taxes
155,498 (4,888) -
Income tax benefit
(7,705) (1,193) -
Equity in earnings of subsidiaries from continuing operations 317,222 254,463 242,522
Income from continuing operations 480,425 250,768 242,522
Equity in earnings (loss) of subsidiaries from discontinued operations (17,922) 125,726 135,609
Discontinued operations, net of tax
(47,796) (9,005) -
Net income $ 414,707 $ 367,489 $ 378,131
Comprehensive income $ 414,600 $ 377,910 $ 385,205
The accompanying notes are an integral part of these condensed financial statements.
MDU Resources Group, Inc. Form 10-K 123
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MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Balance Sheets
December 31, 2023 2022
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents $ 33,039 $ 19,486
Receivables, net 6,568 4,410
Accounts receivable from subsidiaries 30,526 53,285
Prepayments and other current assets 8,261 3,237
Total current assets 78,394 80,418
Noncurrent assets
Investments 37,722 50,206
Investment in subsidiaries 3,146,122 3,581,754
Notes receivable from subsidiaries
58,000 -
Deferred income taxes 12,596 12,668
Operating lease right-of-use assets 31 72
Other 2,593 2,068
Total noncurrent assets 3,257,064 3,646,768
Total assets $ 3,335,458 $ 3,727,186
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 4,264 $ 2,354
Accounts payable to subsidiaries 3,435 4,402
Notes payable to subsidiaries
134,107 -
Taxes payable 542 572
Dividends payable 25,461 45,246
Accrued compensation 9,651 4,312
Operating lease liabilities due within one year 25 42
Other accrued liabilities 8,008 17,907
Total current liabilities 185,493 74,835
Noncurrent liabilities:
Long-term debt 189,048 -
Operating lease liabilities 6 30
Other 55,678 65,192
Total noncurrent liabilities 244,732 65,222
Commitments and contingencies
Stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 203,689,090 at December 31, 2023 and 204,162,814 at December 31, 2022
203,689 204,163
Other paid-in capital 1,466,235 1,466,037
Retained earnings 1,253,693 1,951,138
Accumulated other comprehensive loss (18,384) (30,583)
Treasury stock at cost - 538,921 shares at December 31, 2022
- (3,626)
Total stockholders' equity 2,905,233 3,587,129
Total liabilities and stockholders' equity $ 3,335,458 $ 3,727,186
The accompanying notes are an integral part of these condensed financial statements.
124 MDU Resources Group, Inc. Form 10-K
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MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Cash Flows
Years ended December 31, 2023 2022 2021
(In thousands)
Net cash provided by operating activities of continuing operations
$ 271,337 $ 251,204 $ 187,297
Net cash used in operating activities of discontinued operations
$ (47,796) $ (9,005) $ -
Net cash provided by operating activities
223,541 242,199 187,297
Investing activities:
Investments in and advances to subsidiaries (476,000) (45,000) (102,000)
Investments 7,422 (885) (391)
Issuance of notes receivable
(58,000) - -
Net cash used in investing activities of continuing operations
(526,578) (45,885) (102,391)
Financing activities:
Issuance of short-term borrowings 535,000 - -
Repayment of short-term borrowings (242,401) - -
Issuance of long-term debt 575,000 - -
Repayment of long-term debt (385,000) - -
Debt issuance costs
(952) - -
Proceeds from issuance of common stock - (149) 88,767
Dividends paid (161,316) (176,915) (171,354)
Repurchase of common stock (2,270) (3,525) (2,992)
Tax withholding on stock-based compensation (1,471) (2,398) (1,949)
Net cash used in financing activities of continuing operations
316,590 (182,987) (87,528)
Increase (decrease) in cash and cash equivalents 13,553 13,327 (2,622)
Cash and cash equivalents - beginning of year 19,486 6,159 8,781
Cash and cash equivalents - end of year $ 33,039 $ 19,486 $ 6,159
The accompanying notes are an integral part of these condensed financial statements.
MDU Resources Group, Inc. Form 10-K 125
Index
Part IV
Notes to Condensed Financial Statements
Note 1 - Summary of Significant Accounting Policies
Basis of presentation The condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of Regulation S-X. The information is unconsolidated and is presented for the parent company only, MDU Resources Group, Inc. (the Company) as of and for the years ended December 31, 2023, 2022 and 2021. In Schedule I, investments in subsidiaries are presented under the equity method of accounting where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on the Condensed Balance Sheets. The income from subsidiaries is reported as equity in earnings of subsidiaries on the Condensed Statements of Income. The material cash inflows on the Condensed Statements of Cash Flows are primarily from the dividends and other payments received from its subsidiaries and the proceeds raised from the issuance of debt and equity securities. The consolidated financial statements of the Company reflect certain businesses as discontinued operations. These statements should be read in conjunction with the consolidated financial statements and notes thereto of the Company.
Earnings per common share Please refer to the Consolidated Statements of Income of the registrant for earnings per common share. In addition, see Item 8 - Note 2 for information on the computation of earnings per common share.
Note 2 - Debt
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. At December 31, 2023, there were no amounts outstanding under the agreement.
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.
On November 6, 2023, the Company entered into a $310 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.
At December 31, 2023, the Company had $190 million of long-term debt maturities for 2025. For more information on debt, see Item 8 - Note 10.
Note 3 - Dividends The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. Cash dividends paid to the Company by subsidiaries were $165.5 million, $242.1 million and $188.1 million for the years ended December 31, 2023, 2022 and 2021, respectively.
126 MDU Resources Group, Inc. Form 10-K
Index
Part IV
Exhibits
Incorporated by Reference
Exhibit Number Exhibit Description Filed Herewith Form Period Ended Exhibit Filing Date File Number
*2(a)
Separation and Distribution Agreement, dated as of May 30, 2023, by and between Knife River Corporation and MDU Resources Group, Inc.
8-K 2.1 6/1/23 1-03480
3(a) Amended and Restated Certificate of Incorporation of MDU Resources Group, Inc.
8-K 3.2 5/8/19 1-03480
3(b) Amended and Restated Bylaws of MDU Resources Group, Inc.
8-K 3.1 2/15/19 1-03480
4(a) Indenture, dated as of December 15, 2003, between MDU Resources Group, Inc. and The Bank of New York, as trustee
S-8 4(f) 1/21/04 333-112035
4(b) First Supplemental Indenture, dated as of November 17, 2009, between MDU Resources Group, Inc. and the Bank of New York Mellon, as trustee
10-K 12/31/09 4(c) 2/17/10 1-03480
**4(c)
Montana-Dakota Utilities Co. Amended and Restated Credit Agreement, dated December 19, 2019, among Montana-Dakota Utilities Co., Various Lenders, and Wells Fargo Bank, National Association, as Administrative Agent
10-K 12/31/19 4(d) 2/21/20 1-03480
4(d)
Montana-Dakota Utilities Co. Note Purchase Agreement, dated July 24, 2019, among Montana-Dakota Utilities Co. and various purchasers of the notes
10-Q 9/30/19 4(a) 11/1/19 1-03480
4(e)
MDU Resources Group, Inc. Description of Securities Registered Pursuant to Section 12 of the Securities and Exchange Act of 1934
10-K 12/31/19 4(g) 2/21/20 1-03480
**4(f)
WBI Energy Transmission, Inc. Second Amendment and Restatement Note Purchase and Private Shelf Agreement, effective as of December 22, 2022, among Prudential Investment Management, Inc. and certain investors described therein
10-K 12/31/22 4(h)
2/24/23 1-03480
**10(a)
Transition Services Agreement, dated as of May 30, 2023, by and between Knife River Corporation and MDU Resources Group, Inc.
8-K 10.1 6/1/23 1-03480
10(b)
Tax Matters Agreement, dated as of May 30, 2023, by and between Knife River Corporation and MDU Resources Group, Inc.
8-K 10.2 6/1/23 1-03480
10(c)
Employee Matters Agreement, dated as of May 30, 2023, by and between Knife River Corporation and MDU Resources Group, Inc.
8-K 10.3 6/1/23 1-03480
**10(d)
5-Year Revolving Credit Agreement, dated as of May 31, 2023, by and among MDU Resources Group, Inc., the financial institutions from time to time party thereto and U.S. Bank National Association.
8-K 10.5 6/1/23 1-03480
**10(e)
364-Day Revolving Credit Agreement, dated as of May 31, 2023, by and among MDU Resources Group, Inc., the financial institutions from time to time party thereto and U.S. Bank National Association.
8-K 10.6 6/1/23 1-03480
**10(f)
Term Loan Agreement, dated as of May 31, 2023, by and among MDU Resources Group, Inc., the lenders from time to time party thereto and U.S. Bank National Association.
8-K 10.7 6/1/23 1-03480
+10(g) MDU Resources Group, Inc. Supplemental Income Security Plan, as amended and restated May 10, 2017
10-Q 6/30/17 10(d) 8/4/17 1-03480
+10(h) MDU Resource Group, Inc. Director Compensation Policy, as amended May 11, 2022
10-Q 6/30/22 10(b) 8/5/22 1-03480
+10(i) Deferred Compensation Plan for Directors, as amended May 15, 2008
10-Q 6/30/08 10(a) 8/7/08 1-03480
+10(j) Non-Employee Director Stock Compensation Plan, as amended May 12, 2011
10-Q 6/30/11 10(a) 8/5/11 1-03480
+10(k) MDU Resources Group, Inc. Non-Employee Director Long-Term Incentive Compensation Plan, as amended May 17, 2012
10-Q 6/30/12 10(a) 8/7/12 1-03480
MDU Resources Group, Inc. Form 10-K 127
Index
Part IV
Incorporated by Reference
Exhibit Number Exhibit Description Filed Herewith Form Period Ended Exhibit Filing Date File Number
+10(l) MDU Resources Group, Inc. Long-Term Performance-Based Incentive Plan, as amended February 15, 2024
8-K
10.2 2/21/24 1-03480
+10(m) MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended November 12, 2020, and Rules and Regulations, as amended November 12, 2020
10-K 12/31/20 10(h) 2/19/21 1-03480
+10(n) Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 11, 2021
10-K 12/31/20 10(l) 2/19/21 1-03480
+10(o) Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 17, 2022
10-K 12/31/21 10(k) 2/23/22 1-03480
+10(p) Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 11, 2021
10-K 12/31/20 10(n) 2/19/21 1-03480
+10(q) Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 17, 2022
10-K 12/31/21 10(m) 2/23/22 1-03480
+10(r) Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 16, 2023
10-K 12/31/22 10(m) 2/24/23 1-03480
+10(s) Form of MDU Resources Group, Inc. Indemnification Agreement for Section 16 Officers and Directors, dated May 15, 2014
8-K 10.1 5/15/14 1-03480
+10(t) Form of Amendment No. 1 to Indemnification Agreement, dated May 15, 2014
8-K 10.2 5/15/14 1-03480
+10(u) MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of February 14, 2024
X
+10(v) MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as amended and restated November 12, 2020
10-K 12/31/20 10(r) 2/19/21 1-03480
+10(w) MDU Resources Group, Inc. Deferred Compensation Plan Adoption Agreement, as amended August 12, 2021
10-Q 9/30/21 10(c) 11/4/21 1-03480
+10(x) MDU Resources Group, Inc. Deferred Compensation Plan Document, dated November 12, 2020
8-K 10.2 11/12/20 1-03480
+10(y) MDU Resources Group, Inc. 401(k) Retirement Plan, as restated April 1, 2020
10-Q 3/31/20 10(a) 5/8/20 1-03480
+10(z) First Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended December 17, 2020
10-K 12/31/20 10(u)
2/19/21 1-03480
+10(aa) Second Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended January 1, 2021
10-Q
3/31/21 10(a) 5/6/21 1-03480
+10(ab) Third Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended January 1, 2022
10-K 12/31/21 10(w) 2/23/22 1-03480
+10(ac) Fourth Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended August 17, 2022
10-Q 9/30/22 10(a) 11/3/22 1-03480
+10(ad) Fifth Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended December 28, 2022
10-K
12/31/22 10(w) 2/24/23 1-03480
+10(ae) Sixth Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended May 1, 2023
X
+10(af) Seventh Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended August 23, 2023
X
+10(ag) Eighth Amendment to MDU Resources Group, Inc. 401(k) Retirement Plan, as amended January 1, 2024
X
+10(ah) Employment Letter for Jeffrey S. Thiede, dated May 16, 2013
10-K 12/31/13 10(ab) 2/21/14 1-03480
+10(ai) Jason L. Vollmer Offer Letter, dated September 20, 2017
8-K 10.1 9/21/17 1-03480
128 MDU Resources Group, Inc. Form 10-K
Index
Part IV
Incorporated by Reference
Exhibit Number Exhibit Description Filed Herewith Form Period Ended Exhibit Filing Date File Number
+10(aj) Cooperation Agreement, dated as of January 24, 2023, by and among Keith A. Meister, Corvex Management LP and MDU Resources Group, Inc.
8-K 10.1 1/24/23 1-03480
+10(ak) David C. Barney Offer Letter, dated February 17, 2023
10-K
12/31/22 10(ab)
2/24/23 1-03480
+10(al) MDU Resources Group, Inc. Change in Control Severance Plan
8-K
10.1 2/21/24 1-03480
21 Subsidiaries of MDU Resources Group, Inc.
X
23 Consent of Independent Registered Public Accounting Firm
X
31(a) Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
31(b) Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
32 Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
X
+97 Incentive Compensation Recovery Policy
X
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
101.LAB XBRL Taxonomy Extension Label Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Certain exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally to the Securities and Exchange Commission a copy of any omitted exhibits or schedules upon request; provided that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended.
** Schedules and exhibits to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted
schedule and/or exhibit will be furnished as a supplement to the SEC upon request.
+ Management contract, compensatory plan or arrangement.
MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.