MDU RESOURCES GROUP INC - Annual Report: 2021 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ______________

Commission file number 1-03480

MDU RESOURCES GROUP INC

(Exact name of registrant as specified in its charter)


Delaware						30-1133956
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, par value $1.00 per share	MDU	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒.

State the aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2021: $6,339,561,129.

Indicate the number of shares outstanding of the registrant's common stock, as of February 15, 2022: 203,350,740 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Relevant portions of the registrant's 2022 Proxy Statement, to be filed no later than 120 days from December 31, 2021, are incorporated by reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.

Contents


Part I		Page

Forward-Looking Statements		7

Items 1 and 2 Business and Properties		7
	General	7
	Electric	11
	Natural Gas Distribution	15
	Pipeline	17
	Construction Materials and Contracting	18
	Construction Services	22

Item 1A	Risk Factors	23

Item 1B	Unresolved Staff Comments	31

Item 3	Legal Proceedings	31

Item 4	Mine Safety Disclosures	31

Part II

Item 5	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32

Item 6	Reserved	32

Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	33

Item 7A	Quantitative and Qualitative Disclosures About Market Risk	62

Item 8 Financial Statements and Supplementary Data		63
	Consolidated Statements of Income	68
	Consolidated Statements of Comprehensive Income	69
	Consolidated Balance Sheets	70
	Consolidated Statements of Equity	71
	Consolidated Statements of Cash Flows	72
	Notes to Consolidated Financial Statements	73
	1. Basis of Presentation	73
	2. Significant Accounting Policies	74
	3. Revenue from Contracts with Customers	81
	4. Business Combinations	83
	5. Property, Plant and Equipment	84
	6. Regulatory Assets and Liabilities	85
	7. Goodwill and Other Intangible Assets	86
	8. Fair Value Measurements	87
	9. Debt	89
	10. Leases	91
	11. Asset Retirement Obligations	92
	12. Equity	92
	13. Stock-Based Compensation	93
	14. Accumulated Other Comprehensive Loss	94
	1 5 . Income Taxes	95
	1 6 . Cash Flow Information	97

2 MDU Resources Group, Inc. Form 10-K

Contents


Part II (continued)		Page
	1 7 . Business Segment Data	97
	1 8 . Employee Benefit Plans	100
	19. Jointly Owned Facilities	109
	20. Regulatory Matters	109
	21. Commitments and Contingencies	110


Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	115

Item 9A	Controls and Procedures	115

Item 9B	Other Information	115

Item 9C	Disclosure Regarding Foreign Jurisdiction that Prevents Inspection	115

Part III

Item 10	Directors, Executive Officers and Corporate Governance	116

Item 11	Executive Compensation	116

Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116

Item 13	Certain Relationships and Related Transactions, and Director Independence	116

Item 14	Principal Account ant Fees and Services	116

Part IV

Item 15	Exhibits, Financial Statement Schedules	117

3. Exhibits		121

Item 16	Form 10-K Summary	123

Signatures		124

MDU Resources Group, Inc. Form 10-K 3

Definitions


The following abbreviations and acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym
AFUDC			Allowance for funds used during construction
Army Corps			U.S. Army Corps of Engineers
ASC			FASB Accounting Standards Codification
ASU			FASB Accounting Standards Update
Audit Committee			Audit Committee of the board of directors of the Company
Bcf			Billion cubic feet
Big Stone Station			475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BSSE			345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota (50 percent ownership)
Btu			British thermal unit
CARES Act			United States Coronavirus Aid, Relief, and Economic Security Act
Cascade			Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CDC			Centers for Disease Control and Prevention
Centennial			Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital			Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial's Consolidated EBITDA			Centennial's consolidated net income from continuing operations plus the related interest expense, taxes, depreciation, depletion, amortization of intangibles and any non-cash charge relating to asset impairment for the preceding 12-month period
CERCLA			Comprehensive Environmental Response, Compensation and Liability Act
Company			MDU Resources Group, Inc.
COVID-19			Coronavirus disease 2019
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)
CyROC			Cyber Risk Oversight Committee
dk			Decatherm
Dodd-Frank Act			Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA			Earnings before interest, taxes, depreciation, depletion and amortization
EIN			Employer Identification Number
EPA			United States Environmental Protection Agency
ERISA			Employee Retirement Income Security Act of 1974
ESA			Endangered Species Act
Exchange Act			Securities Exchange Act of 1934, as amended
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
GHG			Greenhouse gas
Great Plains			Great Plains Natural Gas Co., a public utility division of Montana-Dakota
GVTC			Generation Verification Test Capacity
Holding Company Reorganization			The internal holding company reorganization completed on January 1, 2019, pursuant to the agreement and plan of merger, dated as of December 31, 2018, by and among Montana-Dakota, the Company and MDUR Newco Sub, which resulted in the Company becoming a holding company and owning all of the outstanding capital stock of Montana-Dakota.
IBEW			International Brotherhood of Electrical Workers
ICWU			International Chemical Workers Union
Intermountain			Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC			Idaho Public Utilities Commission
Item 8			Financial Statements and Supplementary Data
Knife River			Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest			Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River

4 MDU Resources Group, Inc. Form 10-K

Definitions


K-Plan			Company's 401(k) Retirement Plan
kW			Kilowatts
kWh			Kilowatt-hour
LIBOR			London Inter-bank Offered Rate
MD&A			Management's Discussion and Analysis of Financial Condition and Results of Operations
Mdk			Thousand dk
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
MDUR Newco			MDUR Newco, Inc., a public holding company created by implementing the Holding Company Reorganization, now known as the Company
MDUR Newco Sub			MDUR Newco Sub, Inc., a direct, wholly owned subsidiary of MDUR Newco, which was merged with and into Montana-Dakota in the Holding Company Reorganization
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
MMBtu			Million Btu
MMcf			Million cubic feet
MMdk			Million dk
MNPUC			Minnesota Public Utilities Commission
Montana-Dakota			Montana-Dakota Utilities Co. a direct wholly owned subsidiary of MDU Energy Capital
MPPAA			Multiemployer Pension Plan Amendments Act of 1980
MTDEQ			Montana Department of Environmental Quality
MTPSC			Montana Public Service Commission
MW			Megawatt
NDDEQ			North Dakota Department of Environmental Quality
NDPSC			North Dakota Public Service Commission
NERC			North American Electric Reliability Corporation
Non-GAAP			Not in accordance with GAAP
Oil			Includes crude oil and condensate
OPUC			Oregon Public Utility Commission
PCAOB			Public Company Accounting Oversight Board
PCBs			Polychlorinated biphenyls
PHMSA			Pipeline and Hazardous Material Safety Administration
Proxy Statement			Company's 2022 Proxy Statement to be filed no later than April 29, 2022
PRP			Potentially Responsible Party
RCRA			Resource Conservation and Recovery Act
RNG			Renewable Natural Gas
RP			Rehabilitation plan
SDPUC			South Dakota Public Utilities Commission
SEC			United States Securities and Exchange Commission
Securities Act			Securities Act of 1933, as amended
Sheridan System			A separate electric system owned by Montana-Dakota
SOFR			Secured Overnight Financing Rate
SPP			Southwest Power Pool, the organization that manages the electric grid and wholesale power market for the central United States.
UA			United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
TSA			Transportation Security Administration
VIE			Variable interest entity
Washington DOE			Washington State Department of Ecology
WBI Energy			WBI Energy, Inc., an indirect wholly owned subsidiary of Centennial
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

MDU Resources Group, Inc. Form 10-K 5

Definitions


WUTC			Washington Utilities and Transportation Commission
Wygen III			100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYDEQ			Wyoming Department of Environmental Quality
WYPSC			Wyoming Public Service Commission
ZRCs			Zonal resource credits - a MW of demand equivalent assigned to generators by MISO for meeting system reliability requirements

6 MDU Resources Group, Inc. Form 10-K

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Part I

Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - MD&A - Business Segment Financial and Operating Data.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, the impact of COVID-19 on the Company's business, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished and changes in such assumptions and factors could cause actual future results to differ materially.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and, except as required by law, the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.


Items 1 and 2. Business and Properties

General

The Company is a regulated energy delivery and construction materials and 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 with a two-platform model of regulated energy delivery and construction materials and services, while pursuing organic growth opportunities and strategic acquisitions of well-managed companies and properties. Each of the Company's platforms are comprised of different operating segments. Most of these segments experience seasonality related to the industries in which they operate. The two-platform approach helps balance this seasonality and the risks associated with each type of industry. Through its regulated energy delivery platform, 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 materials and services platform provides construction services to a variety of industries, including commercial, industrial and governmental customers, and provides construction materials through aggregate mining and marketing of related products, such as ready-mix concrete, asphalt and asphalt oil.

The Company is organized into five reportable business segments. These business segments include: electric, natural gas distribution, pipeline, construction materials and contracting, 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, Knife River, MDU Construction Services and Centennial Capital. WBI Energy is the pipeline segment, Knife River is the construction materials and contracting 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 17.

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 At the core of Building a Strong America® is 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 41 states plus Washington D.C. as of December 31, 2021. The number of employees fluctuates during the year due to the seasonality and the number and size of construction projects. During 2021, the number of employees peaked in the second quarter at just over 14,700. Employees as of December 31, 2021, 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.

8 MDU Resources Group, Inc. Form 10-K

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Part I

The following information is as of December 31, 2021.


Company	Collective-bargaining agreement	Number of employees represented	Agreement status
Montana-Dakota	IBEW	327	Effective through April 30, 2024
Intermountain	UA	132	Effective through March 31, 2023
Cascade	ICWU	194	Effective through March 31, 2024
WBI Energy Transmission	IBEW	70	Effective through March 31, 2022
Knife River	40 various agreements	452	2 agreements in negotiations
MDU Construction Services	103 various agreements	5,488	1 agreement in negotiations
Total		6,663

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 shareholder 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:

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, 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. In markets where labor availability is tight, when possible, the Company uses telecommuting, guaranteed hours, flexible schedules and work arrangements to fill open positions.

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 at least every two years 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 The Company is committed to safety and health in the workplace. To ensure safe work environments, the Company provides training, adequate 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.

In response to COVID-19, the Company established a task force to monitor developments related to the pandemic and implemented procedures to protect employees. The Company adopted recommended practices and procedures by the CDC and other governmental entities, and is following the rules and directives of applicable federal, state and local jurisdictions in which the Company operates.


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. Until legislation and regulation are finalized, the impact of these measures cannot be accurately predicted. 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.

In 2021, the Company formed 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.

10 MDU Resources Group, Inc. Form 10-K

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Part I


			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 21. 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 Portland, Oregon, Harbor Superfund Site and the Bremerton Gasworks Superfund Site. For more information on the Company's environmental matters, see Item 8 - Note 21.

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.

The Company created CyROC to oversee its approach to cybersecurity. CyROC is responsible for supplying management and the Audit Committee with analyses, appraisals, recommendations and pertinent information concerning cyber defense of the Company’s electronic information and information technology systems. A quarterly cybersecurity report is provided to the Audit Committee. For a discussion of the Company's risks related to cybersecurity, see Item 1A - Risk Factors.

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 15 electric generating units at 11 facilities and two small portable diesel generators, as further described under System Supply, System Demand and Competition, approximately 3,500 and 4,800 miles of transmission and distribution lines, respectively, and 83 transmission and 294 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, 2021, Montana-Dakota's net electric plant investment was $1.6 billion and its rate base was $1.3 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.

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Part I

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.

The retail customers served and respective revenues by class for the electric business were as follows:


	2021			2020			2019
	Customers Served	Revenues		Customers Served	Revenues		Customers Served	Revenues
	(Dollars in thousands)
Residential	119,113	$	123,043	118,893	$	122,545	118,563	$	125,614
Commercial	23,149	133,336		23,050	131,207		22,948	142,062
Industrial	231	40,477		230	36,736		234	37,790
Other	1,610	6,754		1,609	6,601		1,601	7,454
	144,103	$	303,610	143,782	$	297,089	143,346	$	312,920

Other electric revenues, which are largely transmission-related revenues, for Montana-Dakota were $46.0 million, $34.9 million and $38.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.

The percentage of electric retail revenues by jurisdiction was as follows:


	2021		2020		2019
North Dakota	64	%	64	%	65	%
Montana	22	%	22	%	22	%
Wyoming	9	%	9	%	8	%
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. The interconnected system consists of 14 electric generating units at 10 facilities and two small portable diesel generators. Additional details are included in the table that follows. For 2021, Montana-Dakota's total ZRCs, including its firm purchase power contracts, were 535.0. Montana-Dakota's planning reserve margin requirement within MISO was 530.8 ZRCs for 2021. The maximum electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was 611,542 kW in August 2015. 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 2021, Montana-Dakota purchased approximately 29 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 69,404 kW in July 2021. 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, 2023. Wygen III also serves a portion of the needs of Montana-Dakota's Sheridan-area customers.

Approximately 29 percent of the electricity delivered to customers from Montana-Dakota's owned generation in 2021 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 30 percent since 2005 through the addition of renewable generation. Montana-Dakota's carbon dioxide emissions are expected to continue to decline through the retirement of aging coal-fired electric generating units, as further discussed below.

In February 2019, Montana-Dakota announced the retirement of three aging coal-fired electric generating units. The Company ceased operations on March 31, 2021, of Unit 1 at Lewis & Clark Station in Sidney, Montana, and commenced decommissioning in July 2021. Units 1 and 2 at Heskett Station near Mandan, North Dakota, are being retired during the first quarter of 2022. In addition, during the first half of 2022, Montana-Dakota will begin construction of a new 88-MW simple-cycle natural gas-fired combustion turbine peaking unit at the existing Heskett Station.

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Part I

The following table sets forth details applicable to the Company's electric generating stations:


Generating Station	Type	Fuel	Nameplate Rating (kW)	2021 ZRCs	(a)	2021 Net Generation (kWh in thousands)
Interconnected System:
North Dakota:
Coyote (b)	Steam	Coal	103,647	94.0		620,045
Heskett	Steam	Coal	86,000	—		501,446
Heskett	Combustion turbine	Natural gas	89,038	70.9		7,325
Glen Ullin	Renewable	Heat recovery	7,500	3.4		44,771
Cedar Hills	Renewable	Wind	19,500	3.7		58,221
Thunder Spirit	Renewable	Wind	155,500	22.2		556,575
South Dakota:
Big Stone (b)	Steam	Coal	94,111	106.5		375,130
Montana:
Lewis & Clark (c)	Steam	Coal	44,000	—		64,733
Lewis & Clark	Reciprocating internal combustion engine	Natural gas	18,700	18.0		3,779
Glendive	Combustion turbine	Natural gas / diesel	75,522	68.9		16,346
Miles City	Combustion turbine	Natural gas / diesel	23,150	21.0		2,974
Diamond Willow	Renewable	Wind	30,000	5.1		92,757
Portable Units (2)	Reciprocating internal combustion engine	Diesel	3,650	3.6		14
			750,318	417.3		2,344,116
Sheridan System:
Wyoming:
Wygen III (b)	Steam	Coal	28,000	N/A		207,348
			778,318	417.3		2,551,464

(a)Interconnected system only. MISO requires generators to obtain their summer 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.

(c)Retired March 31, 2021.

Virtually all of the current fuel requirements of Heskett station is met with coal supplied by a wholly-owned subsidiary of Westmoreland Mining LLC under a contract that expires in March 2022. The Heskett coal supply agreement provides for the purchase of coal necessary to supply the coal requirements of the Heskett Station at contracted pricing. Montana-Dakota estimates the Heskett coal requirement to be 40,000 tons through March 2022 for Heskett.

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 21.

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 2022. 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 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 2025. 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.

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 20.

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 Title V Operating Permits by facility for the electric business were as follows:


Facility	Application Date	Issuance Date	Issuing Body
Wygen III *	To be submitted timely in 2022	Not specified at this time	WYDEQ
Lewis & Clark Station	Submitted timely in December 2019	May 13, 2021	MTDEQ
Miles City	Submitted timely in December 2020	November 5, 2021	MTDEQ
Glendive	Submitted timely in December 2020	December 9, 2021	MTDEQ

*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 is expected to be submitted in 2022. Wygen III is currently allowed to operate under the facility's construction permit until the Title V Operating Permit is issued.

State water discharge permits issued under the requirements of the federal Clean Water Act are maintained for power production facilities on the Yellowstone and Missouri rivers. 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 did not incur any material environmental capital expenditures in 2021. Environmental capital expenditures are estimated to be $4.1 million and $2.9 million in 2022 and 2023, respectively, for closure of coal ash management units at Lewis & Clark Station and Heskett Station. Montana-Dakota does not expect to incur any material capital expenditures related to environmental compliance in 2024. Montana-Dakota's capital and operational expenditures could also be affected by future environmental requirements, such as regional haze emission reductions. For more information, see Item 1A - Risk Factors.

14 MDU Resources Group, Inc. Form 10-K

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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 20,900 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, 2021, the natural gas distribution operations' net natural gas distribution plant investment was $2.0 billion and its rate base was $1.4 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:


	2021			2020			2019
	Customers Served	Revenues		Customers Served	Revenues		Customers Served	Revenues
	(Dollars in thousands)
Residential	905,535	$	548,091	887,429	$	480,466	868,821	$	479,673
Commercial	110,196	330,468		108,788	281,175		107,741	293,201
Industrial	939	31,103		929	26,217		906	26,570
	1,016,670	$	909,662	997,146	$	787,858	977,468	$	799,444

Transportation and other revenues for the natural gas distribution operations were $62.3 million, $60.3 million and $65.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.

The percentage of the natural gas distribution operations' retail sales revenues by jurisdiction was as follows:


	2021		2020		2019
Idaho	27	%	30	%	29	%
Washington	29	%	30	%	28	%
North Dakota	15	%	13	%	15	%
Montana	10	%	8	%	9	%
Oregon	8	%	8	%	8	%
South Dakota	6	%	6	%	6	%
Minnesota	3	%	3	%	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.

MDU Resources Group, Inc. Form 10-K 15

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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 Pipeline, Inc., Ruby Pipeline LLC, Foothills Pipe Lines Ltd., NOVA Gas Transmission Ltd, TC Energy Corporation and Northwest Natural. 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 beyond 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 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. A final determination has not yet been made.

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. The facilitation plan will be vital in supporting the growth and development of the RNG industry in the state of Idaho.

For more information on regulatory matters, see Item 8 - Note 20.

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.

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.

16 MDU Resources Group, Inc. Form 10-K

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The natural gas distribution operations did not incur any material environmental expenditures in 2021. Except as to what may be ultimately determined with regard to the issues described in the following paragraph, the natural gas distribution operations do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2024.

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 21 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 3,700 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 13 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, 2021, its net plant investment was $762.4 million. The non-regulated business of this segment provides a variety of energy-related services, including cathodic protection and energy efficiency product sales and installation services to large end-users.

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 North Bakken Expansion project, to increase transportation and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide future benefits.

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 2021 represented 23 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.

MDU Resources Group, Inc. Form 10-K 17

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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.

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.

The pipeline operations did not incur any material environmental expenditures in 2021 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2024.

Construction Materials and Contracting


			General Knife River mines, processes and sells construction aggregates (crushed stone, sand and gravel); produces and sells asphalt mix; and supplies ready-mix concrete. These products are used in most types of construction, performed by Knife River and other companies, including roads, freeways and bridges, as well as homes, schools, shopping centers, office buildings and industrial parks. Knife River focuses on vertical integration of its contracting services with its construction materials to support the aggregate-based product lines including aggregate placement, asphalt and concrete paving, and site development and grading. Although not common to all locations, other products include the sale of cement, asphalt oil for various commercial and roadway applications, various finished concrete products and other building materials and related contracting services. During 2021, Knife River's acquisitions included Mt. Hood Rock, a construction aggregates business in Oregon, as well as Baker Rock Resources and Oregon Mainline Paving, two premier construction material companies located around the Portland, Oregon metro area. For more information on business combinations, see Item 8 - Note 4.

Competition Knife River's construction materials products and contracting services are marketed under competitive conditions. Price is the principal competitive force to which these products and services are subject, with service, quality, delivery time and proximity to the customer also being significant factors. Knife River focuses on markets located near aggregate sites to reduce transportation costs which allows Knife River to remain competitive with the pricing of aggregate products. The number and size of competitors varies in each of Knife River's principal market areas and product lines.

The demand for construction materials products and contracting services is significantly influenced by the cyclical nature of the construction industry. In addition, activity in certain locations may be seasonal in nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending on roads and infrastructure projects, general economic conditions within the market area that influence the commercial and residential sectors, and prevailing interest rates.

Knife River's customers are a diverse group which includes federal, state and municipal governmental agencies, commercial and residential developers, and private parties. The mix of sales by customer class varies each year depending on available work. Knife River 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 construction materials businesses.

Reserve Information Aggregate reserve estimates are calculated based on the best available data. This data is collected from drill holes and other subsurface investigations, as well as investigations of surface features such as mine high walls and other exposures of the aggregate reserves. Mine plans, production history and geologic data are also utilized to estimate reserve quantities. Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data described previously are used to calculate the thickness of aggregate materials to be recovered.

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Topography associated with alluvial sand and gravel deposits is typically flat and volumes of these materials are calculated by applying the thickness of the resource over the areas available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground is used for sand and gravel deposits.

Topography associated with hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries.

Geotechnical studies are conducted on a deposit to determine its suitability for use as construction aggregates. Drilling is performed at each site using the most appropriate method of recovery. Cored samples are logged with detail as governed by industry standards by a registered geologist and stored in the company's possession until delivered to the testing lab. Drilled samples may be logged by either registered geologists or internal personnel based on the Unified Soil Classification System. The geologist's log sheets are compared against published geological maps for reference and assistance in determining a formation's extent.

Collected samples are delivered to a certified lab for testing of the chemical and physical properties to determine the potential use of the deposit. These tests include the determination of the mineral's hardness and soundness, its chemical reactivity and the presence of objectionable substances, and are performed within the procedures set forth by the American Society for Testing and Materials, the American Association of State Highway and Transportation Officials or the state or local department of transportation.

The classification and quantity of a particular deposit is further analyzed by reviewing the geological formation, test results and production processes, along with modifying factors, to determine an expected yield of recoverable tonnage an area will produce. These results may have an effect on mine plans and the selection of processing equipment. These results are reviewed by the qualified individual and presented to the management team.

Management assesses the risks associated with resource and reserve computations of aggregate deposits. These computations may be affected by variability in the properties of the material, limits of the accuracy of the geotechnical data and operational difficulties in extraction of the computed material. Additionally, management assesses the risks associated in obtaining and maintaining the various land use, mining and environmental permits which are necessary for the properties to operate as mines. Annual reviews of mining reserves are conducted by the qualified individual and includes procedures such as ensuring financial assumptions related to life of mine expenses are based on the most accurate estimates available.

Reserve estimates are based on analyses of the data described above by qualified internal mining engineers, operating personnel and third-party geologists. Senior management reviews and approves the reserve estimates, including the major assumptions used in determining the estimates including life, pricing, cost and volume, among other things, to ensure they are materially accurate. For aggregate reserve additions, management, which includes the qualified individual, reviews the study of technical, economic and operating factors. As part of management's process of performing due diligence on the properties, management also reviews supplemental information including a summary of the site's geotechnical report. The Company also maintains a database of all aggregate reserves which is reconciled at least annually and reviewed and approved by the qualified individual(s).

The Company's estimated reserves are primarily proven reserves. The reserve estimates include only salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 1.1 billion tons of Knife River's 1.2 billion tons of aggregate reserves are permitted reserves. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The remaining reserves are on properties that are expected to be permitted for mining under current regulatory requirements. The data used to calculate the remaining reserves may require revisions in the future to account for changes in customer requirements and unknown geological occurrences. The remaining reserve life (years) was calculated by dividing remaining reserves by the three-year average sales, including estimated sales from acquired reserves prior to acquisition, from 2019 through 2021. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer demand, customer specifications, geological conditions and changes in mining plans. The Company has reviewed its properties and has determined it does not have any individual sites that are material.

MDU Resources Group, Inc. Form 10-K 19

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The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2021, and sales for the years ended December 31, 2021, 2020 and 2019:


	Crushed Stone				Sand & Gravel				Total Estimated Reserves (000's tons)
Production Area (b)	Number of Sites		Estimated Reserves (000's tons)		Number of Sites		Estimated Reserves (000's tons)				Tons Sold (000's)			Lease Expiration	Reserve Life (years)
	owned	leased			owned	leased					2021	2020	2019
Alaska	—	—	—		1	—	13,583		13,583		780	817	868	N/A	17
California	—	2	90,290		9	1	36,025		126,315		2,766	2,417	2,193	2028-2035	51
Hawaii	—	6	45,096		—	—	—		45,096		1,417	1,466	1,680	2023-2064	30
Idaho	—	—	—		8	1	28,439		28,439		2,460	2,565	2,138	2028	12
Minnesota	3	1	16,228		49	9	60,765		76,993		4,133	3,528	3,654	2022-2032	20
Montana	—	—	—		12	—	72,636		72,636		3,157	3,081	2,906	N/A	24
North Dakota	—	—	—		3	16	24,958		24,958		1,102	1,027	986	2022-2028	24
Oregon	11	14	385,920		19	11	192,192		578,112		8,467	8,063	8,567	2022-2077	53	(a)
South Dakota	2	—	34,048		1	2	1,667		35,715		3,651	3,689	2,914	2025-2028	10
Texas	2	2	19,288		3	—	61,070		80,358		1,336	984	1,378	2022-2029	65
Wyoming	2	6	89,643		1	5	29,969		119,612		1,817	840	837	2024-2085	103
Sales from other sources											2,432	2,472	4,193
	20	31	680,513	(c)	106	45	521,304	(c)	1,201,817	(c)	33,518	30,949	32,314

(a)Includes estimate of three-year average sales for acquired reserves.

(b)The Company's reserve properties are in a production stage.

(c)Table reflects approximately 67.9 million tons of measured resources that are currently not permitted, but expected to be permitted in future years.

The Company's management and qualified individual perform an analysis of current and historical pricing when estimating the reasonable and justifiable price for reserves. Current pricing is typically heavily weighted in the price assumption and is reviewed and approved by management. If available, the Company will also compare pricing to similarly located reserves. The average price per ton in 2021 for crushed stone and sand and gravel was $14.83 and $9.76, respectively. The price for each commodity was calculated by dividing 2021 revenues by tons sold.

20 MDU Resources Group, Inc. Form 10-K

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The 1.2 billion tons of estimated aggregate reserves at December 31, 2021, are comprised of 646 million tons on properties that are owned and 556 million tons that are leased. Approximately 45 percent of the tons under lease have lease expiration dates of 20 years or more. The weighted average years remaining on all leases containing estimated proven aggregate reserves is approximately 21 years, including options for renewal that are at Knife River's discretion. Based on a three-year average of sales from 2019 through 2021 of leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 45 years. Some sites have leases that expire prior to the exhaustion of the estimated reserves. The estimated reserve life assumes, based on Knife River's experience, that leases will be renewed to allow sufficient time to fully recover these reserves.

The changes in Knife River's aggregate reserves for the years ended December 31 were as follows:


	2021	2020	2019
		(000's of tons)
Aggregate reserves:
Beginning of year	1,104,887	1,054,186	1,014,431
Purchases (a)	135,005	114,666	71,157
Sales volumes (b)	(31,086)	(28,477)	(28,121)
Other (c)	(6,989)	(35,488)	(3,281)
End of year	1,201,817	1,104,887	1,054,186

(a)Includes reserves from recent business combinations.

(b)Excludes sales from other sources.

(c)Includes property sales, revisions of previous estimates and expiring leases.

Environmental Matters Knife River's construction materials and contracting operations are subject to regulation customary for such operations, including federal, state and local environmental compliance and reclamation regulations. Except as to the issues described later, Knife River strives to be in compliance with these regulations. Individual permits applicable to Knife River's various operations are managed and tracked as they relate to the statuses of the application, modification, renewal, compliance and reporting procedures.

Knife River's asphalt and ready-mix concrete manufacturing plants and aggregate processing plants are subject to the federal Clean Air Act and the federal Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities are also subject to these laws. In most of the states where Knife River operates, these regulatory programs are delegated to state and local regulatory authorities. Knife River's facilities are also subject to the RCRA as it applies to the management of hazardous wastes and underground storage tank systems. These programs are generally delegated to the state and local authorities in the states where Knife River operates. Knife River's facilities must comply with requirements for managing wastes and underground storage tank systems.

Certain activities of Knife River are directly regulated by federal agencies. For example, certain in-water mining operations are subject to provisions of the federal Clean Water Act that are administered by the Army Corps. Knife River has several such operations, including gravel bar skimming and dredging operations, and Knife River has the associated required permits. The expiration dates of these permits vary, with five years generally being the longest term.

Knife River's operations are also occasionally subject to the ESA. For example, land use regulations often require environmental studies, including wildlife studies, before a permit may be granted for a new or expanded mining facility or an asphalt or concrete plant. If endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks, restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife River's operations are also subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations or processing plants. Land use permit applications generally require that areas proposed for mining or other surface disturbances be surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements.

The most comprehensive environmental permit requirements are usually associated with new mining operations, although requirements vary widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal. However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are sometimes required before a mining permit application can be considered for approval. These reports can take up to several years to complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic vistas and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts.

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Provisions for public hearings and public comments are usually included in land use permit application review procedures in the counties where Knife River operates. After considering environmental, mine plan and reclamation information provided by the permittee, as well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is rare, but land use permits often include conditions that must be addressed by the permittee. Conditions may include property line setbacks, reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies.

Knife River has been successful in obtaining mining and other land use permits so sufficient permitted reserves are available to support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted aggregate reserve is needed to support Knife River's operations.

Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the Surface Mining Control and Reclamation Act, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne Mine remain under reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond and additional areas are currently in the process of having the bond released. Knife River intends to request bond release as soon as it is deemed possible.

Knife River did not incur any material environmental expenditures in 2021 and, except as to what may be ultimately determined with regard to the issues described in the following paragraph, Knife River does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2024.

In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a commercial property site, acquired by Knife River - Northwest in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For more information, see Item 8 - Note 21.

Mine Safety The Dodd-Frank Act requires disclosure of certain mine safety information. For more information, see Item 4 - Mine Safety Disclosures.

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 country. These specialty contracting services are provided to utilities and 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 distribution of transmission 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, 2021, 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.

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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 relies on 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.

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 environmental expenditures in 2021 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2024.


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.

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 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 businesses. The level of demand for construction products and 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; acts of terrorism; and acts of war. These hazards and operating risks have occurred and may recur in the future which could result in loss of human life; personal injury; property damage; environmental pollution; 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 or interstate natural gas infrastructure could negatively impact the Company's business and reputation. Because the Company's electric and natural gas utility and pipeline systems are part of larger interconnecting systems, a disruption could result in a significant decrease in revenues and 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, including through its "at-the-market" offering program, 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, including COVID-19.

•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 shareholders and/or may adversely affect the market price of the Company's common stock. Higher interest rates on borrowings could also have an adverse effect on the Company's operating results.

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 energy prices could negatively affect the Company's businesses.

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 the economic slowdowns; 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.

If oil and natural gas prices increase significantly, customer demand could decline for utility, pipeline and construction products and 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. High oil prices also affect the margins realized and demand for construction materials and related contracting services.

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COVID-19 may have a negative impact on the Company's business operations, revenues, results of operations, liquidity and cash flows.

The ongoing COVID-19 pandemic has disrupted national, state and local economies. To the extent the COVID-19 pandemic adversely impacts the Company's businesses, operations, revenues, liquidity or cash flows, it could also have a heightened effect on other risks described in this section. The degree to which COVID-19 will impact the Company depends on future developments, including the resurgence of COVID-19 and its variants, federal and state mandates, actions taken by governmental authorities, effectiveness of vaccines being administered, and the pace and extent to which the economy recovers and remains under relatively normal operating conditions.

The Company's operations have experienced minor disruptions due to shortages of employees or third-party contractors and altered work operations. Government and customer vaccine mandates could leave the Company with a shortage of vaccinated employees or reduce workforce capacity to bid on new projects, which may further exacerbate the already tight labor markets for skilled employees or cause additional wage inflation. The Company could also be impacted by additional costs and lost productivity associated with COVID-19 testing and tracking of employee vaccination records. If a significant percentage of the Company's workforce are unable to work because of illness, quarantine, vaccination requirements or government restrictions in connection with the COVID-19 pandemic, the Company's operations may be negatively impacted, potentially adversely affecting its business, operations, revenues, liquidity and cash flows.

In response to the COVID-19 pandemic, the Company implemented a remote work environment for certain employees of the Company's workforce. As of July 2021, many of these employees returned to their office; however, some employees have transitioned to a permanent remote work environment. The increase in remote work and longevity of the pandemic may create increased vulnerability to cybersecurity incidents affecting the Company’s ability to maintain secure operations.

Other factors associated with the COVID-19 pandemic that could impact the Company's businesses and future operating results, revenues and liquidity include impacts related to the health, safety, and availability of employees and contractors; extended rise in unemployment; public and private sector budget changes and constraints; continued flexible payment plans for utility customers; counterparty credit; costs and availability of supplies; capital construction and infrastructure operation and maintenance programs; financing plans; pension valuations; travel restrictions; and legal and regulatory matters, including the potential for delayed regulatory filings, accounting for the impacts of the COVID-19 pandemic and recovery of invested capital. The economic and market disruptions resulting from COVID-19 could also lead to greater than normal uncertainty with respect to the realization of estimated amounts, including estimates for backlog, revenue recognition, intangible assets, other investments and provisions for credit losses.

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, 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, construction materials and contracting 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.

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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.

The Company’s energy delivery infrastructure is aging, which increases certain risks, including breakdown or failure of equipment, pipeline leaks and fires developing from power lines, all of which have occurred and may recur 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 an 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. 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, and aggregate reserves 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; 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. Additionally, in a number of states in which the Company operates, it can be difficult to permit new aggregate sites or expand existing aggregate sites due to community resistance. 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 backlogs at the Company's construction materials and contracting and construction services businesses 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. Disruptions or delays in receiving materials; price increases from suppliers or manufacturers; or inability to source needed materials 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.

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 materials and contracting and construction services businesses. In addition, drought conditions could restrict the availability of water supplies, inhibiting the ability of the construction businesses to conduct operations.

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 materials and 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 to combat 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.

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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, aggregate permitting 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, permitting and environmental compliance for construction material facilities, 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.

Initiatives related to global climate change and to reduce GHG emissions could adversely impact the Company's operation, costs of or access to capital and impact or limit business plans.

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. 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. Approximately 42 percent of Montana-Dakota's owned generating capacity and approximately 69 percent of the electricity it generated in 2021 was from 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 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 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.

There have also been recent 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 accessing the capital markets or insurance; 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.

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, such as heavy or sustained rainfall or snowfall, storms, wind and colder weather may affect the demand for products and the ability to perform services at the construction businesses 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

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damage, which could require additional remediation costs. The Company could also be impacted by drought conditions, which may restrict the availability of water supplies and inhibit the ability of the construction businesses to conduct operations. 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. Construction materials products are marketed under highly competitive conditions and are subject to competitive forces such as price, service, delivery time and proximity to the customer. 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 or economic downturns, 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 materials and contracting and construction services businesses may be exposed to warranty claims.

The Company, particularly its construction businesses, 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 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 69 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. Based on available information, the Company believes that approximately 28 percent of the MEPPs to which it contributes are currently in endangered, seriously endangered or critical status.

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.

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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 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 and facilities for delivery of construction materials or other products and services, 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 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. 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.

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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.

•Inability of contract counterparties to meet their contractual obligations.

•The inability to effectively integrate the operations and the internal controls of acquired companies.


Item 1B. Unresolved Staff Comments

The Company has no unresolved comments with the SEC.


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 21, which is incorporated herein by reference.


Item 4. Mine Safety Disclosures

For information regarding mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, see Exhibit 95 to this Form 10-K, which is incorporated herein by reference.

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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, 2021, the Company's common stock was held by approximately 9,900 stockholders of record.

The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid uninterrupted dividends to stockholders for 84 consecutive years with an increase in the payout amount for the last 31 consecutive years. 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 12.

The following table includes information with respect to the Company's purchase of equity securities:


ISSUER PURCHASES OF EQUITY SECURITIES
Period	(a) Total Number of Shares (or Units) Purchased (1)	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) 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, 2021	—	—	—	—
November 1 through November 30, 2021	41,925	$28.98	—	—
December 1 through December 31, 2021	372	$30.85	—	—
Total	42,297	$29.00	—	—

(1) Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors and for those directors who elected to receive additional shares of common stock in lieu of a portion of their cash retainer.

(2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.


Item 6.

Reserved.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation

The Company is Building a Strong America® by providing essential infrastructure and services through its regulated energy delivery and construction materials and services businesses. 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 building roads, highways, data infrastructure and airports.

The Company's two-platform business model, regulated energy delivery and construction materials and services, are each comprised of different operating segments. Most of these segments experience seasonality related to the industries in which they operate. The two-platform approach helps balance this seasonality and the risks associated with each type of industry. The Company is authorized to conduct business in nearly every state and during peak construction season has employed over 16,000 employees. 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.

The Company continues to effectively execute its strategy while managing the ongoing effects of the COVID-19 pandemic. Since early 2020, the Company has maintained its business continuity plans as well as a task force to monitor developments related to the pandemic allowing the Company to continue to provide safe and reliable services. Most of the Company's products and services are considered essential to its country and communities and, as a result, operations have generally continued throughout the pandemic.

Certain of the Company's supply vendors are facing production and staffing challenges as they work to achieve production capacity and lead times consistent with pre-pandemic levels. Coupled with other challenges of the pandemic, these vendors are also experiencing strong demand from the residential construction market, some industrial segments and some utility infrastructure investments. In addition, freight markets continue to have challenges with driver shortages; strong demand for consumer goods; extended lead times; and costs for vehicles, driver retention and recruitment. The Company has implemented measures to proactively order supplies and work with additional suppliers to ensure work continues without delays; however, the Company has experienced some delays on delivery of certain materials as well as cost pressures from supply chain disruptions and commodity price inflation.

The situation surrounding COVID-19 and the potential impacts on the Company and the economy remain fluid. A number of factors could directly impact the Company and the economy, including a widespread resurgence in COVID-19 infections, whether due to the spread of variants of the virus or otherwise; the rate of vaccinations; vaccine mandates; labor constraints; the strength of the global supply chain; and the rate in which governments are re-opening businesses or, in certain jurisdictions, reversing re-opening decisions. Due to the uncertainty of the economic outlook resulting from the COVID-19 pandemic, the Company continues to monitor the situation closely. Although there have been logistical and other challenges as a result of COVID-19, there were no material adverse impacts on the Company's results of operations for the years ended December 31, 2021 or 2020. The Company will continue to adjust its business in response to the pandemic while positioning for potential opportunities to enhance its competitive position. For more information specific to each of the Company's business segments, see the following discussions in each business segment's Outlook section. For more information on the possible impacts, see 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,	2021		2020		2019
	(In millions, except per share amounts)
Electric	$	51.9	$	55.6	$	54.8
Natural gas distribution	51.6		44.0		39.5
Pipeline	40.9		37.0		29.6
Construction materials and contracting	129.8		147.3		120.4
Construction services	109.4		109.7		93.0
Other	(5.9)		(3.1)		(2.1)

Income from continuing operations	377.7		390.5		335.2
Income (loss) from discontinued operations, net of tax	.4		(.3)		.3

Net income	$	378.1	$	390.2	$	335.5
Earnings per share - basic:
Income from continuing operations	$	1.87	$	1.95	$	1.69
Discontinued operations, net of tax	—		—		—
Earnings per share - basic	$	1.87	$	1.95	$	1.69
Earnings per share - diluted:
Income from continuing operations	$	1.87	$	1.95	$	1.69
Discontinued operations, net of tax	—		—		—
Earnings per share - diluted	$	1.87	$	1.95	$	1.69

2021 compared to 2020 The Company's consolidated earnings decreased $12.1 million.

Negatively impacting the Company's earnings was a decrease in gross margin across most product lines at the construction materials and contracting business resulting from labor constraints; increased material costs, including asphalt oil and fuel; higher equipment, repair and maintenance costs; and less available paving work in certain regions. The decrease was partially offset by higher AFUDC for the construction of the North Bakken Expansion project and higher earnings due to increased natural gas transportation volumes at the pipeline business. Also positively impacting earnings were higher adjusted gross margins at the electric and natural gas businesses, largely a result of approved rate relief in certain jurisdictions, partially offset by higher operations and maintenance expenses.

2020 compared to 2019 The Company's consolidated earnings increased $54.7 million.

The Company's earnings were positively impacted by increased earnings across all of the Company's businesses in 2020. The construction materials and contracting business experienced an increase in gross margin, primarily resulting from favorable weather conditions and higher realized materials margins on asphalt and asphalt-related products and ready-mix concrete, as well as most other product lines. The construction services business also experienced an increase in gross margin as a result of higher specialty contracting workloads, partially due to the businesses acquired, as well as hospitality projects, high-tech projects and natural disaster recovery work. The pipeline business experienced increased transportation volumes and revenues, largely related to organic growth projects, as well as higher storage-related revenues as a result of stronger demand for storage services. In addition, approved rate recovery positively impacted earnings at the electric and natural gas distribution businesses.

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 17.

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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 shareholder return, while providing safe, environmentally responsible, reliable and competitively priced energy and related services to customers. 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, the cost of natural gas, cost of electric fuel and purchased power, weather, climate change 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, environmentally responsible, reliable and affordable 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, as further discussed in Items 1 and 2 - Business Properties and Item 8 - Note 20.

The segments are also subject to extensive regulation including certain operational and environmental compliance, cybersecurity, permit terms and system integrity. The natural gas segment recently implemented procedure changes issued by PHSMA that were effective July 1, 2021. 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. Implementation of enhancements and additional requirements 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, including consideration for legislation on clean energy standards and GHG emission, and the Company expects that to continue. 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. These initiatives could result in increased costs to produce electricity and procure natural gas. To date, the impact of these initiatives on the Company is unknown. The Company will continue to monitor the progress of these initiatives 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 February 2021, a prolonged period of unseasonably cold temperatures in the central United States significantly increased the demand for electric and natural gas services and contributed to increased market prices. The Company's transmission settlement process with SPP helped offset the increased energy costs to electric customers during the cold-weather event. Further, in some jurisdictions the Company utilized natural gas in storage to lessen the impact of high natural gas costs. Overall, Montana-Dakota and Great Plains incurred approximately $44.0 million in increased natural gas costs in order to maintain services for its customers. These extraordinary natural gas costs were recorded as regulatory assets as they are expected to be recovered from customers. Montana-Dakota and Great Plains have received approval for the recovery of purchased gas adjustments related to the cold-weather event in all jurisdictions impacted, including out-of-cycle purchased gas adjustment requests in most jurisdictions. The approval in Minnesota is subject to a prudence review by the MNPUC, which is pending, with an order to be issued on or before August 29, 2022. For a discussion of the Company's most recent cases by jurisdiction, see Item 8 - Note 20.

The electric and natural gas distribution segments continue to face increased lead times on delivery of certain raw materials and equipment used in electric 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 of electrical equipment as a result of the COVID-19 pandemic, including delays in shipping times and issuance of permits for large and heavy loads. The Company did not experience significant impacts from these delays for the year ended December 31, 2021.

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However, the Company continues to monitor the material lead times and is working with manufacturers to proactively order such materials and working with additional suppliers to help mitigate the risk of any delays.

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 and competition from other energy providers and fuels. 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.

Earnings overview - The following information summarizes the performance of the electric segment.


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Operating revenues	$	349.6	$	332.0	$	351.7	5.3	%	(5.6)	%
Electric fuel and purchased power	74.1		66.9		86.6		10.8	%	(22.7)	%
Taxes, other than income	.8		.6		.6		33.3	%	—	%
Adjusted gross margin	274.7		264.5		264.5		3.9	%	—	%
Operating expenses:
Operation and maintenance	124.9		121.3		125.7		3.0	%	(3.5)	%
Depreciation, depletion and amortization	66.8		63.0		58.7		6.0	%	7.3	%
Taxes, other than income	16.7		16.8		16.1		(.6)	%	4.3	%
Total operating expenses	208.4		201.1		200.5		3.6	%	.3	%
Operating income	66.3		63.4		64.0		4.6	%	(.9)	%
Other income	4.6		7.2		3.4		(36.1)	%	111.8	%
Interest expense	26.7		26.7		25.3		—	%	5.5	%
Income before income taxes	44.2		43.9		42.1		.7	%	4.3	%
Income tax benefit	(7.7)		(11.7)		(12.7)		(34.2)	%	(7.9)	%
Net income	$	51.9	$	55.6	$	54.8	(6.7)	%	1.5	%

Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross margin attributable to the electric segment, see the Non-GAAP Financial Measures section later in this Item.


Operating statistics
	2021		2020		2019
Revenues (millions)
Retail sales:
Residential	$	123.0	$	122.6	$	125.6
Commercial	133.3		131.2		142.1
Industrial	40.5		36.7		37.8
Other	6.8		6.6		7.4
	303.6		297.1		312.9
Transportation and other	46.0		34.9		38.8
	$	349.6	$	332.0	$	351.7
Retail sales (million kWh)
Residential	1,164.8		1,170.9		1,177.9
Commercial	1,433.0		1,419.4		1,499.9
Industrial	589.4		532.1		549.4
Other	84.4		82.1		87.1
	3,271.6		3,204.5		3,314.3
Average cost of electric fuel and purchased power per kWh	$	.021	$	.019	$	.023

2021 compared to 2020 Electric earnings decreased $3.7 million as a result of:

•Adjusted gross margin increased $10.2 million attributable to:

◦Higher transmission revenues of $3.3 million.

◦Higher transmission interconnect upgrades of $2.4 million.

◦Higher MISO revenue of $2.0 million.

◦Higher demand revenues of $1.5 million.

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◦Increased retail sales volumes of 2.1 percent, largely as a result of increased industrial and commercial sales volumes, offset in part by lower residential sales volumes, as the impacts of the COVID-19 pandemic began to reverse and businesses reopened.

•Operation and maintenance increased $3.6 million.

◦Primarily the result of:

•Higher planned maintenance outage costs of $2.1 million at Big Stone Station and $800,000 higher maintenance fees at Thunder Spirit.

•Higher other miscellaneous expenses.

◦Partially offset by lower payroll-related costs of $700,000, which includes lower employee incentive accruals, offset in part by higher health care costs.

•Depreciation, depletion and amortization increased $3.8 million largely resulting from:

◦Increased property, plant and equipment balances, primarily related to transmission projects placed in service.

◦Increased amortization of plant retirement and closure costs of $1.7 million recovered in operating revenues, as discussed in Item 8 - Note 6.

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

•Other income decreased $2.6 million.

◦Primarily due to:

•The absence of an out-of-period adjustment of $2.5 million in 2020 as a result of previously overstated benefit plan expenses.

•Lower returns on certain of the Company's benefit plan investments of $1.3 million.

◦Partially offset by increased interest income associated with higher contributions in aid of construction.

•Interest expense was comparable to the same period in the prior year.

•Income tax benefit decreased $4.0 million largely resulting from:

◦Lower production tax credits of $2.1 million related to the expiration of the 10-year credit-qualifying period on certain facilities and less wind generation.

◦Lower excess deferred tax amortization.

2020 compared to 2019 Electric earnings increased $800,000 as a result of:

•Adjusted gross margin in 2020 was comparable to that of 2019.

◦Positively impacted by higher rates of $2.8 million, including approved rate relief resulting in $2.0 million additional revenue.

◦Offset by lower retail sales volumes of 3.3 percent across all customer classes due to warmer weather and slow-downs as a result of the COVID-19 pandemic.

•Operation and maintenance expense decreased $4.4 million.

◦Largely due to:

•Lower generation station expenses of $3.5 million.

•Lower payroll and other employee-related costs of approximately $1.5 million.

◦Partially offset by increased bad debt expense of $500,000 as a result of the COVID-19 pandemic, as discussed later.

•Depreciation, depletion and amortization increased $4.3 million largely from:

◦Increased asset base driven by capital expenditures, which include transmission projects.

◦Higher depreciation rates implemented from a Montana rate case of $1.2 million.

•Taxes, other than income increased $700,000 from higher property taxes in certain jurisdictions.

•Other income increased $3.8 million largely attributable to:

◦An out-of-period adjustment of $2.5 million in the fourth quarter of 2020 as a result of previously overstated benefit plan expenses.

◦The absence of the write-down of a non-utility investment in the second quarter of 2019 for $1.2 million.

◦Lower 2020 pension expense.

•Interest expense increased $1.4 million driven by higher short-term debt balances.

•Income tax benefit decreased $1.0 million, largely due to higher income before income taxes.

MDU Resources Group, Inc. Form 10-K 37

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Earnings overview - The following information summarizes the performance of the natural gas distribution segment.


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Operating revenues	$	971.9	$	848.2	$	865.2	14.6	%	(2.0)	%
Purchased natural gas sold	542.0		448.1		477.6		21.0	%	(6.2)	%
Taxes, other than income	34.7		32.4		30.3		7.1	%	6.9	%
Adjusted gross margin	395.2		367.7		357.3		7.5	%	2.9	%
Operating expenses:
Operation and maintenance	194.1		185.4		185.0		4.7	%	.2	%
Depreciation, depletion and amortization	86.0		84.6		79.6		1.7	%	6.3	%
Taxes, other than income	25.9		24.6		23.5		5.3	%	4.7	%
Total operating expenses	306.0		294.6		288.1		3.9	%	2.3	%
Operating income	89.2		73.1		69.2		22.0	%	5.6	%
Other income	8.1		13.5		7.2		(40.0)	%	87.5	%
Interest expense	37.3		36.8		35.5		1.4	%	3.7	%
Income before income taxes	60.0		49.8		40.9		20.5	%	21.8	%
Income tax expense	8.4		5.8		1.4		44.8	%	NM
Net income	$	51.6	$	44.0	$	39.5	17.3	%	11.4	%

* NM - not meaningful

Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross margin attributable to the natural gas distribution segment, see the Non-GAAP Financial Measures section later in this Item.


Operating statistics
	2021		2020		2019
Revenues (millions)
Retail sales:
Residential	$	548.1	$	480.5	$	479.7
Commercial	330.4		281.2		293.2
Industrial	31.1		26.2		26.5
	909.6		787.9		799.4
Transportation and other	62.3		60.3		65.8
	$	971.9	$	848.2	$	865.2
Volumes (MMdk)
Retail sales:
Residential	65.6		65.5		69.4
Commercial	44.7		44.2		49.1
Industrial	5.0		4.8		5.2
	115.3		114.5		123.7
Transportation sales:
Commercial	1.9		2.0		2.2
Industrial	172.5		158.0		163.9
	174.4		160.0		166.1
Total throughput	289.7		274.5		289.8
Average cost of natural gas per dk	$	4.70	$	3.91	$	3.86

2021 compared to 2020: Natural gas distribution earnings increased $7.6 million as a result of:

•Adjusted gross margin increased $27.5 million.

◦Largely as a result of:

•Approved rate relief in certain jurisdictions of $15.9 million.

•Increased retail sales volumes of 0.7 percent across all customer classes, including the benefit of weather normalization and decoupling mechanisms in certain jurisdictions.

•Increased transportation volumes of 9 percent, primarily to electric generation customers.

•Higher non-regulated project revenues of $1.7 million.

•Increased basic service charges due to customer growth and increased per unit average rates of $1.5 million each.

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•Operation and maintenance increased $8.7 million.

◦Primarily due to:

•Higher payroll-related costs of $4.3 million, largely related to health care costs and straight-time payroll.

•Decreased credits of $2.4 million for costs associated with the installation of meters partially from delaying meter replacements for safety measures implemented as a result of the COVID-19 pandemic.

•Higher expenses for materials, new software, insurance and vehicle fuel.

◦Partially offset by:

•The absence of the write-off of an abandoned project in the third quarter of 2020 for $1.2 million.

•Decreased bad debt expense of $1.0 million as the impacts of the COVID-19 pandemic began to subside.

•Depreciation, depletion and amortization increased $1.4 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 $4.0 million.

•Taxes, other than income increased $1.3 million resulting from:

◦Higher property taxes in certain jurisdictions of $700,000.

◦Higher payroll taxes driven by increased payroll-related costs.

•Other income decreased $5.4 million primarily related to:

◦The absence of an out-of-period adjustment of $4.4 million in 2020 as a result of previously overstated benefit plan expenses.

◦Decreased interest income related to the recovery of purchased gas cost adjustment balances in certain jurisdictions.

•Interest expense increased $500,000, primarily from lower AFUDC borrowed.

•Income tax expense increased $2.6 million due to higher income before income taxes.

2020 compared to 2019 Natural gas distribution earnings increased $4.5 million as a result of:

•Adjusted gross margin increased $10.4 million.

◦Largely the result of:

•Approved rate recovery of $6.8 million in certain jurisdictions.

•Higher basic service charges of $2.1 million due to customer growth of 2 percent.

•Increased property tax tracker revenue of $1.7 million, which offsets the property tax expense below.

◦Slightly offset by decreased retail sales volumes of 7.4 percent across all customer classes due to warmer weather and slow-downs as a result of the COVID-19 pandemic, largely offset by weather normalization and decoupling mechanisms in certain jurisdictions.

•Operation and maintenance increased $400,000.

◦Primarily related to:

•Increased contract services, largely $1.2 million for the write-off of an abandoned project in the third quarter of 2020.

•Increased software expenses.

◦Partially offset by lower employee-related costs of $1.6 million as a result of the COVID-19 pandemic.

•Depreciation, depletion and amortization increased $5.0 million, primarily from an increase in asset base driven by capital expenditures, which include system safety and reliability enhancements and other growth projects.

•Taxes, other than income increased $1.1 million due to:

◦Higher property taxes in certain jurisdictions of $1.7 million.

◦Partially offset by lower payroll taxes.

•Other income increased $6.3 million.

◦Largely driven by:

•An out-of-period adjustment of $4.4 million in the fourth quarter of 2020 as a result of previously overstated benefit plan expenses.

•Lower 2020 benefit plan expenses of approximately $2.2 million.

•The absence of the write-down of a non-utility investment of approximately $800,000 in the second quarter of 2019.

◦Partially offset by a decrease in interest income of $1.5 million related to the recovery of purchased gas cost adjustment balances.

•Interest expense increased $1.3 million, primarily attributable to increased long-term debt balances, partially offset by lower short-term borrowings.

•Income tax expense increased $4.4 million as a result of:

◦Higher income before income taxes.

◦Permanent tax adjustments.

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Outlook The Company continues to assess the impacts of the COVID-19 pandemic on its operations and is committed to providing safe and reliable service while ensuring the health and safety of its employees, customers and the communities in which it operates. In 2020, the Company instituted certain measures to help protect its employees from exposure to COVID-19 and to curb potential spread of the virus in customer homes and facilities, including suspension of disconnects due to nonpayment of bills, and continued to adjust and reduce these measures in 2021. In April 2020, the Company waived late payment fees to help customers experiencing financial hardships. As of October 2021, the Company had reinstated disconnects in all states of operation and late payment fees in a majority of states. As a consequence of the suspended disconnects and waived late fees, the Company's cash flows and collection of receivables have been affected but impacts have not been material. The Company experienced some impacts to its commercial and industrial electric and natural gas loads associated with reduced economic activity due to the COVID-19 pandemic and oil price impacts, as further discussed below, which began to transition back to historic levels in 2021. The Company filed requests for the use of deferred accounting for costs related to the COVID-19 pandemic in all of the jurisdictions in which it operates and has since withdrawn its applications in three of those jurisdictions. The Company has deferred an immaterial amount of costs related to the pandemic to date.

The Company expects these segments will grow rate base by approximately 5 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 2021 and 2020, these segments experienced retail customer growth of approximately 1.7 percent and 1.8 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. On July 1, 2021, the Company filed in North Dakota, and provided a courtesy copy to South Dakota, an integrated resource plan for the electric segment, which included the Company's plans for future resources to meet customer demand. This integrated resource plan was filed in Montana on September 15, 2021.

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 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. During the third and fourth quarters of 2021, the Company experienced increased natural gas prices and expects this trend to continue through the winter due to the increase in demand outpacing the supply. The Company will continue to monitor natural gas prices, as well as oil and natural gas production levels.

In February 2019, the Company announced the retirement of three aging coal-fired electric generating units, resulting from the Company's analysis showing that the plants are no longer expected to be cost competitive for customers. The Company ceased operations on March 31, 2021, of Unit 1 at Lewis & Clark Station in Sidney, Montana, and commenced decommissioning in July 2021. Units 1 and 2 at Heskett Station near Mandan, North Dakota, are being retired during the first quarter of 2022. In addition, during the first half of 2022, the Company will begin 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 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. State implementation of pollution control plans to improve visibility at Class I areas, such as national parks, under the EPA's Regional Haze Rule 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 a draft state implementation plan to the EPA and federal land managers of the National Park Service, the United States Fish and Wildlife Service and the United States Forest Service for consultation, and the federal land managers have submitted comments back to the NDDEQ for review. North Dakota determined it is not reasonable to require controls during this planning period. The emissions modeling conducted for the combined western state agencies affected by the Regional Haze Rule was delayed and has subsequently delayed the NDDEQ state implementation plan process. Therefore, the NDDEQ's state implementation plan, which was due to the EPA by July 2021, is anticipated to be submitted to EPA in the first half of 2022. Additionally, in September 2021, Otter Tail Power Company filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station with an anticipated exit from the plant by December 31, 2028. The joint owners continue to collaborate in analyzing data and weighing decisions that impact the plant and each company's employees, customers and communities served.

The Company continues to monitor legislation related to clean energy standards that may impact its segments. The current presidential administration is considering changes to the federal Clean Air Act, some of which were amended by the previous presidential administration. The content and impacts of the changes under consideration are uncertain and the Company continues to monitor for potential actions by the EPA. 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, which may be achieved through surrendering emissions allowances, 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. 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, which may be achieved through increased energy efficiency and conservation measures, purchased emission allowances and offsets, and purchases of low carbon fuels. The Washington DOE has begun the Climate Commitment Program rule-making process and is expected to publish a final rule in the

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fall of 2022. The Company has begun reviewing compliance options and expects the compliance costs for these regulations will be recovered through customer rates.

The Company continues to be focused on the regulatory recovery of its investments by filing for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed by regulators. The Company's most recent cases by jurisdiction are discussed in Item 8 - Note 20.

Pipeline

Strategy and challenges The pipeline segment provides natural gas transportation, underground storage and 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 following were organic growth projects for the Company in 2021 and 2020:

•The North Bakken Expansion project in western North Dakota, construction began in July of 2021 and was placed in service in February of 2022. 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.

•Phase II of the Line Section 22 Expansion project in the Billings, Montana, area was placed in service in September of 2020. The completion of Phase I and II increased capacity by 22.5 MMcf per day.

•The Demicks Lake Expansion project in McKenzie County, North Dakota, was placed in service in February of 2020 and increased capacity by 175 MMcf per day.

In April 2020 and November 2020, the Company completed the sales of its regulated and non-regulated natural gas gathering assets, respectively. With the completion of these sales, the Company has exited the natural gas gathering business.

The segment is exposed to energy price volatility which is impacted by the fluctuations in pricing, production and basis differentials of the energy market's commodities. 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 also subject to extensive regulation including 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 pipeline segment recently implemented procedural changes for additional regulations to strengthen the safety of natural gas transmission and storage facilities and hazardous liquid pipelines issued by PHSMA that were effective July 1, 2021. 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. Groups opposing natural gas pipelines could also cause negative impacts on the segment with increased costs, potential delays to project completion or cancellation of prospective projects.

The segment regularly experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work. Long lead times on materials could delay maintenance work and construction projects potentially causing lost revenues and/or increased costs. Current national supply chain challenges did not have significant impacts to the procurement of raw materials for the year ended December 31, 2021. However, the Company is actively monitoring the situation and working with its manufacturers and suppliers to help mitigate the risk of delays.

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.

MDU Resources Group, Inc. Form 10-K 41

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Earnings overview - The following information summarizes the performance of the pipeline segment.


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Operating revenues	$	142.6	$	143.9	$	140.4	(.9)	%	2.5	%
Operating expenses:
Operation and maintenance	61.3		59.9		63.1		2.3	%	(5.1)	%
Depreciation, depletion and amortization	20.5		21.7		21.2		(5.5)	%	2.4	%
Taxes, other than income	12.7		12.9		13.3		(1.6)	%	(3.0)	%
Total operating expenses	94.5		94.5		97.6		—	%	(3.2)	%
Operating income	48.1		49.4		42.8		(2.6)	%	15.4	%
Other income	9.4		2.9		1.2		224.1	%	141.7	%
Interest expense	7.0		7.6		7.2		(7.9)	%	5.6	%
Income before income taxes	50.5		44.7		36.8		13.0	%	21.5	%
Income tax expense	9.6		7.7		7.2		24.7	%	6.9	%
Net income	$	40.9	$	37.0	$	29.6	10.5	%	25.0	%


Operating statistics
	2021	2020	2019
Transportation volumes (MMdk)	471.1	438.6	429.7
Natural gas gathering volumes (MMdk)	—	8.6	13.9
Customer natural gas storage balance (MMdk):
Beginning of period	25.5	16.2	13.9
Net injection (withdrawal)	(2.5)	9.3	2.3
End of period	23.0	25.5	16.2

2021 compared to 2020 Pipeline earnings increased $3.9 million as a result of:

•Revenues decreased $1.3 million.

◦Primarily decreased gathering revenues of $4.9 million due to the sale of the Company's natural gas gathering assets in 2020.

◦Partially offset by:

•Increased transportation volumes and demand revenue of $1.8 million largely from organic growth projects, as previously discussed, and short-term discounted contracts.

•Increased non-regulated project revenues of $1.4 million.

•Operation and maintenance increased $1.4 million due to:

◦The absence of the gain on sale of the Company's natural gas gathering assets of $1.5 million in 2020, offset partially by lower operating expenses related to the natural gas gathering assets.

◦Partially offset by lower payroll-related costs.

•Depreciation, depletion and amortization decreased $1.2 million.

◦Primarily related to lower expense of $1.6 million due to the sale of the Company's natural gas gathering assets in 2020, as previously discussed.

◦Slightly offset by increased property, plant and equipment balances related to organic growth projects.

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

•Other income increased $6.5 million.

◦Primarily due to:

•Higher AFUDC of $7.3 million for the construction of the North Bakken Expansion project.

•The absence of the write-off of unrecovered gas costs and project expenses of $1.2 million in 2020.

◦Partially offset by:

•The absence of a positive impact of $700,000 related to the sale of the Company's regulated gathering assets in 2020.

•The absence of an out-of-period adjustment of $500,000 in 2020 as a result of previously overstated benefit plan expenses.

•Lower returns on certain of the Company's benefit plan investments.

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•Interest expense decreased $600,000.

◦Primarily due to:

•Higher AFUDC of $1.5 million for the construction of the North Bakken Expansion project.

•Lower average interest rates.

◦Partially offset by higher debt balances.

•Income tax expense increased $1.9 million.

◦Largely a result of:

•Higher income before income taxes.

•The absence of the reversal of excess deferred taxes of $1.5 million associated with the sale of the Company's gas gathering assets in 2020.

◦Partially offset by permanent tax adjustments and an energy efficiency tax benefit.

2020 compared to 2019 Pipeline earnings increased $7.4 million as a result of:

•Revenues increased $3.5 million.

◦Primarily the result of:

•Increased transportation volumes and demand revenue of $6.2 million largely from organic growth projects, as previously discussed.

•Increased storage-related revenues of $4.6 million as a result of stronger demand for storage services.

•Additional revenues of $2.4 million primarily from increased rates effective May 1, 2019, due to the FERC rate case finalized in September 2019.

◦Partially offset by:

•Lower non-regulated project revenues of $5.3 million.

•Lower volumes associated with the sale of the Company's natural gas gathering assets in 2020 and lower gathering rates resulting in a decrease in revenues of $4.3 million.

•Operation and maintenance decreased $3.2 million.

◦Largely driven by:

•Decreased non-regulated project costs of $3.7 million associated with lower non-regulated project revenue.

•A $1.5 million gain on the sale of the Company's non-regulated natural gas gathering assets in 2020.

◦Partially offset by higher payroll-related costs.

•Depreciation, depletion and amortization increased $500,000.

◦Primarily due to:

•Additional expense of $1.3 million associated with increased property, plant and equipment balances as a result of organic growth projects that have been placed into service.

•Higher depreciation rates effective May 1, 2019, due to the FERC rate case finalized in September 2019.

◦Partially offset by lower expense of $1.5 million due to the sale of the Company's natural gas gathering assets in 2020.

•Taxes, other than income decreased $400,000.

◦Driven by lower expense due to the sale of the Company's natural gas gathering assets in 2020.

◦Partially offset by higher property taxes in certain jurisdictions of $300,000.

•Other income increased $1.7 million.

◦As a result of:

•Higher AFUDC of $1.1 million.

•A positive impact of $700,000 related to the sale of the Company's regulated gathering assets.

•An out-of-period adjustment of $500,000 in the fourth quarter of 2020 as a result of previously overstated benefit plan expenses.

◦Partially offset by a write-off of unrecovered gas costs and project expenses of $1.2 million.

•Interest expense increased $400,000, primarily from higher debt balances to finance organic growth projects.

•Income tax expense increased $500,000.

◦Directly resulting from higher income before income taxes.

◦Largely offset by the reversal of excess deferred taxes of $1.5 million associated with the sale of the Company's regulated natural gas gathering assets.

Outlook The Company continues to manage the impacts of the COVID-19 pandemic on its operations and is committed to providing safe, reliable and compliant service while ensuring the health and safety of its employees, customers and the communities in which it operates. Overall, the pipeline business has experienced some impacts due to COVID-19 and does not expect significant delays to its regulatory filings or projects due to the pandemic.

In February 2021, the FERC issued a revised notice of inquiry seeking new information and stakeholder perspectives regarding the certification of new interstate natural gas facilities. The FERC issued the original notice of inquiry seeking stakeholder perspectives on this topic in April 2018. The FERC also took a step toward reforming the way in which it analyzes GHG emissions for purposes of natural gas pipeline certificates by including a quantitative analysis of the GHG emissions associated with a pipeline replacement project. At this time, no accepted methodology for a GHG

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significance calculation has been established. A technical conference led by FERC Staff discussing methods natural gas companies may use to mitigate the effects of direct and indirect GHG emissions was held on November 19, 2021. No clear guidance resulted from the conference and comments regarding various questions raised at the conference were due to the FERC on January 7, 2022. On February 18, 2022, the FERC issued two policy statements. The first is an updated certificate policy statement which will apply in pending and future certificate proceedings and is intended to explain how the FERC will consider applications to construct new interstate natural gas transportation facilities to determine whether a project is in the public convenience and necessity. This updated policy statement includes increased focus on the project purpose and need and environmental impacts. This update also focuses on impacts to landowners and environmental justice communities. The second is an interim policy statement which 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. Under the interim version of the policy statement, the FERC will proceed with the preparation of an environmental impact statement if a project may result in emissions of 100,000 metric tons per year of carbon dioxide equivalents or more. Comments are due on the interim policy statement by April 4, 2022. The Company continues to monitor and assess these initiatives 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 the volumes of natural gas the Company transports through its system. Although low oil prices slowed 2020 drilling activities and led to the shut-in of certain wells, the recovery of oil prices has allowed producers to bring wells back online and support new drilling. Associated natural gas production in the Bakken has returned to near pre-pandemic levels and is expected to grow due to new oil wells and increasing gas to oil ratios.

The national record levels of natural gas supply has moderated the pressure on natural gas prices and minimized 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 low natural gas prices continues to provide growth opportunity for industrial supply related projects and seasonal pricing differentials provide opportunities for storage services.

The Company continues to focus on growth and improving existing operations through organic projects in all areas in which it operates, which includes additional organic growth projects with local distribution companies and industrial customers in various stages of development.

In January 2019, the Company announced the North Bakken Expansion project, which includes construction of a new pipeline, compression and ancillary facilities to transport natural gas from core Bakken production areas near Tioga, North Dakota, to a new connection with Northern Border Pipeline in McKenzie County, North Dakota. Long-term take or pay customer contracts support the project at an amended design capacity of 250 MMcf per day, which can be readily expanded to meet forecasted natural gas growth levels and customer needs. In February 2020, the Company filed with the FERC its application for this project. In June 2021, the Company received a FERC order issuing a certificate of public convenience and necessity for the project and in July 2021, the FERC granted the Company a notice to proceed with construction. Construction began in July 2021 and the project was placed into service on February 1, 2022.

In July 2021, the Company announced plans for a natural gas pipeline expansion project in eastern North Dakota. The Wahpeton Expansion project consists of 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. Construction is expected to begin in early 2024, depending on regulatory approvals, with an anticipated completion date later in 2024. On September 22, 2021, the Company filed with the FERC a request to initiate the pre-filing review process and received FERC approval of the pre-filing request on September 27, 2021.

Construction Materials and Contracting

Strategy and challenges The construction materials and contracting segment provides an integrated set of aggregate-based construction services, as discussed in Items 1 and 2 - Business Properties. The segment focuses on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthening the long-term, strategic aggregate reserve position through available purchase and/or lease opportunities; enhancing profitability through cost containment, margin discipline and vertical integration of the segment's operations; development and recruitment of talented employees; and continued growth through organic and strategic acquisition opportunities.

A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, asphalt oil, asphalt concrete, ready-mix concrete and related products), complementing and expanding on the segment's expertise. The Company's continued acquisition activity supports this strategy.

As one of the country's largest sand and gravel producers, the segment continues to strategically manage its approximately 1.2 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated. The segment's vertical integration allows it to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. The Company's aggregate reserves are naturally declining and as a result, the Company seeks acquisition opportunities to replace the reserves. In the fourth quarter of 2021, the Company acquired Baker Rock Resources, an aggregates and asphalt supplier located in Beaverton, Oregon. The acquisition included approximately 80 million tons of proven aggregate reserves. In the first quarter of 2021, the Company received the necessary permitting to expand its operation capabilities at its Honey Creek quarry near Austin, Texas. Honey Creek contains an estimated 50 million tons of proven aggregate reserves.

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The construction materials and contracting segment faces challenges that are not under the direct control of the business. The segment operates in geographically diverse and highly competitive markets. Competition can put negative pressure on the segment's operating margins. The segment is also subject to volatility in the cost of raw materials such as diesel fuel, gasoline, asphalt oil, cement and steel. Such volatility can 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. The Company has and will continue to increase its product pricing to keep pace with rising costs. Other variables that can impact the segment's margins include adverse weather conditions, the timing of project starts or completion and declines or delays in new and existing projects due to the cyclical nature of the construction industry and governmental infrastructure spending. Accordingly, operating results in any particular period may not be indicative of the results that can be expected for any other period.

The segment also faces challenges in the recruitment and retention of employees. Trends in the labor market include an aging workforce and availability issues. Most of the markets the segment operates in saw an increase in labor shortages in 2021, largely truck drivers, causing increased labor-related costs. The Company continues to monitor the labor markets and expects labor costs to continue to increase based on the increased demand for services and, to a lesser extent, the recent escalated inflationary environment in the United States. If labor costs continue to increase, it could negatively impact gross margin as the segment continues to face increasing pressure to control costs. The increase in labor shortages also impacts the segments ability to recruit and train a skilled workforce to meet the needs of increasing demand and seasonal work. In order to help attract new workers to the construction industry and enhance the skills of its current employees, the Company has completed a training facility in Oregon. The training facility offers hands-on training for heavy equipment operators and truck drivers, as well as leadership and safety training.

Earnings overview - The following information summarizes the performance of the construction materials and contracting segment.


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		% change		% change
	(In millions)
Operating revenues	$	2,228.9	$	2,178.0	$	2,190.7	2.3	%	(.6)	%
Cost of sales:
Operation and maintenance	1,794.8		1,733.1		1,798.3		3.6	%	(3.6)	%
Depreciation, depletion and amortization	96.8		84.8		74.3		14.2	%	14.1	%
Taxes, other than income	47.7		46.0		44.1		3.7	%	4.3	%
Total cost of sales	1,939.3		1,863.9		1,916.7		4.0	%	(2.8)	%
Gross margin	289.6		314.1		274.0		(7.8)	%	14.6	%
Selling, general and administrative expense:
Operation and maintenance	88.6		89.9		86.3		(1.4)	%	4.2	%
Depreciation, depletion and amortization	4.2		4.8		3.1		(12.5)	%	54.8	%
Taxes, other than income	5.7		4.9		4.6		16.3	%	6.5	%
Total selling, general and administrative expense	98.5		99.6		94.0		(1.1)	%	6.0	%
Operating income	191.1		214.5		180.0		(10.9)	%	19.2	%
Other income	1.3		.8		1.6		62.5	%	(50.0)	%
Interest expense	19.2		20.6		23.8		(6.8)	%	(13.4)	%
Income before income taxes	173.2		194.7		157.8		(11.0)	%	23.4	%
Income tax expense	43.4		47.4		37.4		(8.4)	%	26.7	%
Net income	$	129.8	$	147.3	$	120.4	(11.9)	%	22.3	%


Operating statistics	Revenues						Gross margin
	2021		2020		2019		2021		2020		2019
	(In millions)
Aggregates	$	444.0	$	406.6	$	418.8	$	47.8	$	50.6	$	46.8
Asphalt	339.8		349.9		332.8		37.6		42.5		35.5
Ready-mix concrete	584.4		547.0		526.0		66.1		58.4		46.3
Other products*	344.2		355.6		384.8		59.6		78.8		73.0
Contracting services	1,017.5		1,069.7		1,054.1		78.5		83.8		72.4
Intracompany eliminations	(501.0)		(550.8)		(525.8)		—		—		—
	$	2,228.9	$	2,178.0	$	2,190.7	$	289.6	$	314.1	$	274.0

*Other products includes cement, asphalt oil, merchandise, fabric, spreading and other products that individually are not considered to be a major line of business for the segment.

MDU Resources Group, Inc. Form 10-K 45

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	2021		2020		2019
Sales (thousands):
Aggregates (tons)	33,518		30,949		32,314
Asphalt (tons)	7,101		7,202		6,707
Ready-mix concrete (cubic yards)	4,267		4,087		4,123
Average sales price:
Aggregates (per ton)	$	13.25	$	13.14	$	12.96
Asphalt (per ton)	$	47.86	$	48.58	$	49.62
Ready-mix concrete (per cubic yard)	$	136.94	$	133.86	$	127.58

2021 compared to 2020 Construction materials and contracting's earnings decreased $17.5 million as a result of:

•Revenues increased $50.9 million.

◦Largely the result of:

•Higher aggregate sales volumes from the recent acquisitions contributed $20.1 million and strong demand for airport, commercial and health care work in Oregon added $16.3 million. Also contributing was an additional $1.6 million due to a few large projects in South Dakota. These increases were partially offset by lower volumes in Texas of $2.0 million driven by lower energy-related sales volumes.

•Higher ready-mix concrete volumes from increased commercial and residential demand in Texas contributed $8.2 million, strong demand in Oregon added $7.8 million and recent acquisitions contributed an additional $4.5 million. Ready-mix concrete revenues also benefited from an increase in average sales price in all regions. These increases were partially offset by decreased sales of $14.8 million due to lower demand in Hawaii as a result of the overall slowdown of the travel industry from COVID-19.

◦Partially offset by:

•Decreased contracting revenues partially due to less available paving work in certain regions of $60.0 million and the absence of a few large jobs in 2020 of $17.5 million. These decreases were offset in part by strong demand for health care, agency and commercial work in Oregon of $28.8 million.

•Decreased asphalt volumes primarily due to less available highway paving work in the public sector of $26.2 million in certain regions was partially offset by strong demand in Oregon.

•Gross margin decreased $24.5 million.

◦Primarily due to:

•Lower margins in other product lines, primarily due to higher asphalt oil material costs of $15.1 million, along with repair and maintenance costs of $2.6 million.

•Higher fuel costs of $13.3 million across all product lines.

•Lower contracting services margins resulting from less available paving work of $8.2 million, as previously discussed, and the absence of a few large jobs for $5.2 million. These margins were also impacted by higher fuel costs, as previously discussed.

•Lower asphalt margins resulting from less available paving work of $5.3 million, as previously discussed.

•Lower aggregates margins resulting from reduced work in Hawaii due to the overall slowdown of the travel industry resulting from COVID-19 of $4.0 million, startup costs of $1.3 million associated with new aggregate sites in Texas and $600,000 higher material costs in Alaska. These decreases were partially offset by higher margins due to strong demand in Oregon of $1.7 million and South Dakota of $1.9 million along with the effects of recent acquisitions.

•Labor constraints, especially truck drivers, which resulted in isolated project delays and staffing inefficiencies across the business.

◦Partially offset by an increase in ready-mix concrete margins of $7.7 million due in part to higher average pricing in all regions and higher volumes in most regions.

•Selling, general and administrative expense decreased $1.1 million.

◦Largely the result of:

•The recovery of prior bad debt expense of $1.6 million.

•Higher gains on asset sales of $900,000.

◦Offset in part by:

•Increased payroll-related costs of $900,000, primarily for higher health care costs.

•Higher acquisition costs of $700,000.

•An increase in miscellaneous taxes, license and governmental fees.

•Other income increased $500,000, primarily resulting from an out-of-period adjustment in 2020 as a result of previously overstated benefit plan expenses.

•Interest expense decreased $1.4 million.

◦Primarily resulting from lower average interest rates of $2.8 million.

◦Offset in part by higher average debt balances.

•Income tax expense decreased $4.0 million as a result of lower income before income taxes.

46 MDU Resources Group, Inc. Form 10-K

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2020 compared to 2019 Construction materials and contracting's earnings increased $26.9 million as a result of:

•Revenues decreased $12.7 million.

◦Largely from lower contracting revenues partially due to lower materials pricing as a result of decreased energy-related costs.

◦Partially offset by higher material sales on most product lines due to an early start to the season, favorable weather conditions in certain regions and additional revenues associated with the businesses acquired.

•Gross margin increased $40.1 million.

◦Largely resulting from:

•An increase to asphalt and asphalt-related product margins by $21.3 million overall due to lower fuel and material costs.

•Strong pricing for ready-mix concrete in most markets resulting in 1.9 percent higher margins.

•Contracting bid margins positively impacted gross margin partially resulting from lower direct costs associated with having a longer construction season due to favorable weather conditions.

•Lower fuel costs across all product lines.

◦Partially offset by lower gains on asset sales in certain regions of approximately $6.8 million.

•Selling, general and administrative expense increased $5.6 million due to:

◦Higher payroll-related costs of $2.2 million.

◦An increase in amortization of intangible assets associated with the businesses acquired.

•Other income decreased $800,000, largely resulting from an out-of-period adjustment to benefit expense in the fourth quarter of 2020 as a result of previously overstated benefit plan expenses.

•Interest expense decreased $3.2 million driven by lower average debt balances in 2020 along with lower average interest rates.

•Income tax expense increased $10.0 million, directly resulting from higher income before income taxes.

Outlook The Company continues to assess the impacts of the COVID-19 pandemic on its operations and is committed to the health and safety of its employees, customers and the communities in which it operates. In 2021, the Company continued to implement safety measures developed in 2020 for its employees that were not able to work from home and experienced some inefficiencies and additional costs in relation to these measures, including delays in the ability to obtain permits from government agencies and, for the most part, has been able to continue business processes with minimal interruptions. The Company also continues to monitor job progress and service work and at this time has not experienced significant delays, cancellations or disruptions due to the pandemic. The American Rescue Plan Act approved by the United States Congress in the first quarter of 2021 provides $1.9 trillion in COVID-19 relief funding for states, schools and local governments. 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 bipartisan infrastructure proposal, known as the Infrastructure Investment and Jobs Act, was approved by the United States Congress in the fourth quarter of 2021. This initiative is providing long-term opportunities by designating $119 billion for the repair and rebuilding of roads and bridges across the Company's footprint. The Company continues to monitor the progress of these legislative items.

The segment's vertically integrated aggregate-based business model provides the Company with the ability to capture margin throughout the sales delivery process. The aggregate products are sold internally and externally for use in other products such as ready-mix concrete, asphaltic concrete and public and private construction markets. The contracting services and construction materials are sold in connection with street, highway and other public infrastructure projects, as well as private commercial, industrial and residential development projects. The public infrastructure projects have traditionally been more stable markets as public funding is more secure during periods of economic decline. The public projects are, however, dependent on federal and state funding such as appropriations to the Federal Highway Administration. Spending on private development is highly dependent on both local and national economic cycles, providing additional sales during times of strong economic cycles.

During 2021 and 2020, the Company made strategic purchases and completed several acquisitions that support the Company's long-term strategy to expand its market presence. In the second quarter of 2021, the Company acquired Mt. Hood Rock, a construction aggregates business located in Portland, Oregon. In the fourth quarter of 2021, the Company acquired Baker Rock Resources, a construction materials company located in Beaverton, Oregon, and Oregon Mainline Paving, an asphalt paving company located in McMinnville, Oregon. The acquisition of Baker Rock Resources complements the segment's Portland Metro operations and replenishes aggregate reserves in a market with high demand. Oregon Mainline Paving also supports the segment's vertically integrated business model. The Company continues to evaluate additional acquisition opportunities. For more information on the Company's business combinations, see Item 8 - Note 4.

The construction materials and contracting segment's backlog remained strong at December 31, 2021, at $708 million, as compared to backlog at December 31, 2020, of $673 million. A significant portion of the Company's backlog relates to street and highway construction. Period over period increases or decreases cannot be used as an indicator of future revenues or net income. The Company expects to complete an estimated $665 million of backlog at December 31, 2021, during the next 12 months. Factors noted in Item 1A - Risk Factors can cause revenues to be realized in periods and at levels that are different from originally projected.

MDU Resources Group, Inc. Form 10-K 47

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Construction Services

Strategy and challenges The construction services segment provides electrical and 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 its 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 highly competitive markets in which it operates. Competitive pricing environments, project delays, changes in management's estimates of variable consideration and the effects from restrictive regulatory requirements have negatively impacted revenues and margins in the past and could affect revenues and margins in the future. Additionally, margins may be negatively impacted on a quarterly basis due to adverse weather conditions, as well as timing of project starts or completions; disruptions to the supply chain due to transportation delays, raw material cost increases and shortages, and closures of businesses or facilities; declines or delays in new projects due to the cyclical nature of the construction industry; and other factors. Current national supply chain challenges did not have significant impacts to the procurement of project materials for the year ended December 31, 2021. However, the Company is actively monitoring the situation and working with its manufacturers and suppliers to help mitigate the risk of delays and price increases. These challenges may also impact the risk of loss on certain projects. 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. These trends include an aging workforce and labor availability issues, as well as increasing duration and complexity of customer capital programs. In 2021, the markets the segment operates in saw an increase in labor shortages which caused increased labor-related costs while the segment continues to face increasing pressure to reduce costs and improve reliability. The Company continues to monitor the labor markets and expects labor costs to continue to increase based on the increased demand for services 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, possibly surpassing the supply of industry resources.

Earnings overview - The following information summarizes the performance of the construction services segment.


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Operating revenues	$	2,051.6	$	2,095.7	$	1,849.3	(2.1)	%	13.3	%
Cost of sales:
Operation and maintenance	1,725.5		1,747.5		1,555.4		(1.3)	%	12.4	%
Depreciation, depletion and amortization	15.8		15.7		15.0		.6	%	4.7	%
Taxes, other than income	62.4		74.2		58.8		(15.9)	%	26.2	%
Total cost of sales	1,803.7		1,837.4		1,629.2		(1.8)	%	12.8	%
Gross margin	247.9		258.3		220.1		(4.0)	%	17.4	%
Selling, general and administrative expense:
Operation and maintenance	92.9		98.1		87.0		(5.3)	%	12.8	%
Depreciation, depletion and amortization	4.5		7.8		2.0		(42.3)	%	NM
Taxes, other than income	4.8		4.8		4.7		—	%	2.1	%
Total selling, general and administrative expense	102.2		110.7		93.7		(7.7)	%	18.1	%
Operating income	145.7		147.6		126.4		(1.3)	%	16.8	%
Other income	2.6		2.0		1.9		30.0	%	5.3	%
Interest expense	3.5		4.1		5.3		(14.6)	%	(22.6)	%
Income before income taxes	144.8		145.5		123.0		(.5)	%	18.3	%
Income tax expense	35.4		35.8		30.0		(1.1)	%	19.3	%
Net income	$	109.4	$	109.7	$	93.0	(.3)	%	18.0	%

* NM - not meaningful

48 MDU Resources Group, Inc. Form 10-K

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Operating Statistics
	Revenues						Gross margin
Business Line	2021		2020		2019		2021		2020		2019
	(In millions)
Electrical & mechanical
Commercial	$	553.2	$	741.5	$	505.8	$	59.8	$	48.4	$	41.9
Industrial	457.5		374.8		344.1		51.3		41.3		32.8
Institutional	123.1		158.8		274.7		6.2		23.8		11.9
Renewables	12.3		5.4		10.4		1.2		1.1		1.6
Service & other	188.4		121.0		139.3		25.1		21.5		25.0
	1,334.5		1,401.5		1,274.3		143.6		136.1		113.2
Transmission & distribution
Utility	630.5		592.5		530.3		92.4		106.7		100.0
Transportation	103.1		111.8		66.0		11.9		15.5		6.9
	733.6		704.3		596.3		104.3		122.2		106.9
Intrasegment eliminations	(16.5)		(10.1)		(21.3)		—		—		—
	$	2,051.6	$	2,095.7	$	1,849.3	$	247.9	$	258.3	$	220.1

2021 compared to 2020 Construction services earnings decreased $300,000 as a result of:

•Revenues decreased $44.1 million.

◦Largely due to:

•The completion of several large commercial projects in early 2021 and 2020 in the Las Vegas market of $129.0 million.

•Decreased institutional projects of $15.0 million from less available work and the completion of a larger project.

•The completion of a significant industrial project of $43.0 million.

•Decreased demand for electric transportation projects which includes traffic signalization and street lighting.

◦Partially offset by:

•Higher industrial work due to the number of projects awarded and progress on significant projects of $96.0 million.

•Increased service work of $37.0 million related to the repair and maintenance of electrical, mechanical and fire protection systems.

•Strong demand for utility projects including the progress on substations of $21.0 million and power line repair of $3.0 million.

•Gross margin decreased $10.4 million.

◦Largely due to:

•The absence of higher margin utility projects in 2020 negatively impacted gross margin by $15.0 million, which includes storm power line repair and fire hardening work.

•Decreased transportation margins, largely the completion of a higher margin project of $5.1 million.

•Institutional projects, primarily the recognition of reduced margins of $9.4 million from lower margin work in 2021 and the impacts of a job loss of $8.4 million related to change order disputes which resulted in a significant job recognizing higher labor and material costs.

◦Partially offset by:

•Increased industrial margins primarily due to a change order settlement of $10.0 million on a significant project.

•The absence of a job loss in 2020 of $8.9 million related to a large commercial project.

•An increase in the amount of service work awarded and the progress on that work.

•Selling, general and administrative expense decreased $8.5 million.

◦Largely due to:

•Lower bad debt expense of $7.0 million, largely due to changes in estimates related to expected credit losses.

•Lower amortization expense of $3.2 million.

◦Offset in part by:

•Higher office expenses of $1.3 million.

•Increased payroll-related costs.

•Other income increased $600,000, largely related to increased earnings on investments.

•Interest expense decreased $600,000, largely related to decreased debt balances due to lower working capital needs and increased cash collections.

•Income tax expense decreased $400,000 as a result of lower income before income taxes.

2020 compared to 2019 Construction services earnings increased $16.7 million as a result of:

•Revenues increased $246.4 million as a result of:

◦Increased electrical and mechanical workloads, largely from higher revenues of $71.4 million due to the addition of PerLectric, Inc. and increased customer demand for high-tech, hospitality and industrial projects. These increases were partially offset by decreased institutional projects.

MDU Resources Group, Inc. Form 10-K 49

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◦Increased transmission and distribution workloads as a result of strong demand for utility projects including storm-related power line repair and wildfire restoration work and increased demand for utility transportation projects.

•Gross margin increased $38.2 million.

◦Primarily resulting from a higher volume of work resulting in an increase in revenues, as previously discussed.

◦Partially offset by an increase in operation and maintenance expense as a direct result of the expenses related to the increased workloads.

•Selling, general and administrative expense increased $17.0 million, largely resulting from:

◦Increased costs of $8.3 million associated with the addition of PerLectric, Inc. operations.

◦Increased allowance for uncollectible accounts of $3.6 million.

◦Higher payroll-related costs of $3.1 million and office expenses.

•Other income was comparable to the same period in the prior year.

•Interest expense decreased $1.2 million, primarily from lower debt balances due to lower working capital needs as a result of payroll tax deferrals and increased cash collections.

•Income tax expense increased $5.8 million, directly resulting from higher income before income taxes.

Outlook The Company continues to assess the impacts of the COVID-19 pandemic on its operations and is committed to the health and safety of its employees, customers and the communities in which it operates. In 2021, the Company continued to implement safety measures developed in 2020 for its employees that were not able to work from home and experienced some inefficiencies in relation to these measures but, for the most part, has been able to continue pre-pandemic business processes. The Company continues to monitor job progress and service work for delays, cancellations and disruptions due to the pandemic and expects possible disruptions to continue in 2022. Despite the challenges presented by the COVID-19 pandemic, the Company believes there are long-term growth opportunities and demand for construction services. The American Rescue Plan act approved by the United States Congress in the first quarter of 2021 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 bipartisan infrastructure proposal, known as the Infrastructure Investment and Jobs Act, was approved by the United States Congress in the fourth quarter of 2021. These include investments for upgrades to electric and grid infrastructure, transportation systems, airports and electric vehicle infrastructure, all industries this segment supports. The Company will continue to monitor the progress of these legislative items.

The Company continued to have bidding opportunities in both specialty contracting markets in 2021 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, wind generation and energy storage markets that complement existing renewable project work performed by the Company.

The construction services segment's backlog at December 31 was as follows:


	2021		2020
	(In millions)
Electrical & mechanical	$	1,109	$	1,059
Transmission & distribution	276		214
	$	1,385	$	1,273

The increase in backlog at December 31, 2021, as compared to backlog at December 31, 2020, was largely attributable to the new project opportunities that the Company continues to be awarded across its diverse operations, particularly within the institutional, renewable and power utility markets. The increases in backlog have been offset by decreases in the commercial, industrial and transportation markets due to the timing of project completions. Period over period increases or decreases cannot be used as an indicator of future revenues or net income. The Company expects to complete an estimated $1.2 billion of the backlog at December 31, 2021, during the next 12 months. Factors noted in Item 1A - Risk Factors can cause revenues to be realized in periods and at levels that are different from originally projected. Additionally, the Company continues to further evaluate potential acquisition opportunities that would be accretive to earnings of the Company and continue to grow the segment's backlog.

50 MDU Resources Group, Inc. Form 10-K

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Other


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Operating revenues	$	13.7	$	11.9	$	16.6	15.1	%	(28.3)	%
Operating expenses:
Operation and maintenance	15.2		12.2		15.6		24.6	%	(21.8)	%
Depreciation, depletion and amortization	4.6		2.7		2.1		70.4	%	28.6	%
Taxes, other than income	.1		.1		.1		—	%	—	%
Total operating expenses	19.9		15.0		17.8		32.7	%	(15.7)	%
Operating loss	(6.2)		(3.1)		(1.2)		(100.0)	%	(158.3)	%
Other income	.4		.4		.9		—	%	(55.6)	%
Interest expense	.3		.8		1.9		(62.5)	%	(57.9)	%
Loss before income taxes	(6.1)		(3.5)		(2.2)		(74.3)	%	(59.1)	%
Income tax benefit	(.2)		(.4)		(.1)		50.0%		NM
Net loss	$	(5.9)	$	(3.1)	$	(2.1)	(90.3)	%	(47.6)%

* NM - not meaningful

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.

Other was negatively impacted in 2021 as a result of higher insurance claims experience at the captive insurer and depreciation expense as compared to 2020. Premiums for the captive insurer were also higher in 2021 compared to 2020, which impacts both operating revenues and operation and maintenance expense.

Other was negatively impacted in 2020 as a result of higher insurance claims as compared to 2019, whereas 2019 had higher insurance premiums which increased both operating revenues and operation and maintenance expense.

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,	2021		2020		2019
	(In millions)
Intersegment transactions:
Operating revenues	$	77.6	$	77.0	$	77.1
Operation and maintenance	18.7		19.1		21.1
Purchased natural gas sold	58.9		57.9		56.0

For more information on intersegment eliminations, see Item 8 - Note 17.

Liquidity and Capital Commitments

At December 31, 2021, the Company had cash and cash equivalents of $54.2 million and available borrowing capacity of $380.0 million under the outstanding credit facilities of the Company's subsidiaries. The Company expects to meet its obligations for debt maturing within 12 months and its other operating and capital requirements from various sources, including internally generated funds; credit facilities and commercial paper of the Company's subsidiaries, as described later in Capital resources; and the issuance of debt and equity securities if necessary.

MDU Resources Group, Inc. Form 10-K 51

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Cash flows


Years ended December 31,	2021		2020		2019
	(In millions)
Net cash provided by (used in)
Operating activities	$	495.8	$	768.4	$	542.3
Investing activities	(885.9)		(630.2)		(603.9)
Financing activities	384.7		(145.1)		74.1
Increase (decrease) in cash and cash equivalents	(5.4)		(6.9)		12.5
Cash and cash equivalents -- beginning of year	59.6		66.5		54.0
Cash and cash equivalents -- end of year	$	54.2	$	59.6	$	66.5

Operating activities


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Income from continuing operations	$	377.7	$	390.5	$	335.2	$	(12.8)	$	55.3
Adjustments to reconcile net income to net cash provided by operating activities	350.9		276.2		309.7		74.7		(33.5)
Receivables	(60.0)		(2.8)		(112.2)		(57.2)		109.4
Inventories	(42.3)		(7.2)		9.3		(35.1)		(16.5)
Other current assets	(72.0)		31.6		(38.3)		(103.6)		69.9
Accounts payable	15.3		16.0		30.1		(.7)		(14.1)
Other current liabilities	(17.6)		35.6		51.3		(53.2)		(15.7)
Pension & postretirement benefit plan contributions	(.5)		(.4)		(25.6)		(.1)		25.2
Other noncurrent changes	(55.4)		30.3		(17.7)		(85.7)		48.0
Net cash provided by (used in) discontinued operations	(.3)		(1.4)		.5		1.1		(1.9)
Net cash provided by operating activities	$	495.8	$	768.4	$	542.3	$	(272.6)	$	226.1

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 also affected by changes in working capital. The decrease in cash flows provided by operating activities from 2021 to 2020 was largely driven by an increase in natural gas purchases and the related unbilled revenues at the natural gas distribution business, as discussed in Item 8 - Notes 2 and 6, partially offset by the associated deferred taxes and increased payables. Also contributing to the decrease was the payment of previously deferred CARES Act taxes and the timing of income tax payments across all of the Company's businesses, as well as the timing of insurance claim payments in relation to receipt of insurance reimbursement at the construction services business. In addition, higher asphalt oil inventory balances due to higher material costs and tank storage balances and higher aggregate inventory balances as a result of production at the businesses acquired at the construction materials and contracting business contributed to the decrease. Partially offsetting the decrease in cash flows provided by operating activities were higher bonus depreciation related to acquisitions at construction materials and contracting business.

The increase in cash flows provided by operating activities from 2020 to 2019 was reflective of the increased earnings across all businesses. The increase in cash flows provided by operating activities was largely driven by stronger collection of accounts receivable at the construction services business and decreased receivables at the construction materials and contracting business as compared to the prior period as a result of lower contracting revenues. Also contributing to the increase in cash flows provided by operating activities was the decrease in natural gas purchases in 2020 as a result of milder temperatures and lower gas costs and recovery of purchased gas cost adjustment balances at the natural gas distribution business. The Company also benefited from the deferral of payroll taxes related to the CARES Act and the absence of pension contributions at all of its businesses. Partially offsetting these increases was higher cash needs due to decreased bonus depreciation for tax purposes taken on qualified property in 2020 as compared to 2019 and a decrease in deferred taxes as a result of the purchased gas cost adjustment recorded in 2019.

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Investing activities


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Capital expenditures	$	(659.4)	$	(558.0)	$	(576.1)	$	(101.4)	$	18.1
Acquisitions, net of cash acquired	(237.7)		(106.0)		(55.6)		(131.7)		(50.4)
Net proceeds from sale or disposition of property and other	15.2		35.6		29.8		(20.4)		5.8
Investments	(4.0)		(1.8)		(2.0)		(2.2)		.2
Net cash used in investing activities	$	(885.9)	$	(630.2)	$	(603.9)	$	(255.7)	$	(26.3)

The increase in cash used in investing activities from 2021 to 2020 was primarily the result of higher cash used in acquisition activity at the construction materials and contracting business, partially offset by decreased acquisition activity at the construction services business. In addition, increased capital expenditures in 2021 at the pipeline business, largely related to the North Bakken Expansion project, and the construction materials and contracting business contributed to the increase, partially offset by lower capital expenditures at the electric and natural gas distribution businesses related to reduced electric transmission and distribution projects and reduced natural gas meters and mains.

The increase in cash used in investing activities from 2020 to 2019 was primarily related to additional cash needs for acquisition activity in 2020 compared to 2019 at the construction businesses, increased capital expenditures in 2020 at the electric business and lower proceeds on asset sales in 2020 at the construction materials and contracting business. Partially offsetting these increases were decreased capital expenditures in 2020 at the construction materials and contracting business, proceeds on the natural gas gathering asset sales at the pipeline business and higher proceeds on asset sales in 2020 at the construction services businesses.

Financing activities


							2021 vs. 2020		2020 vs. 2019
Years ended December 31,	2021		2020		2019		Variance		Variance
	(In millions)
Issuance of short-term borrowings	$	50.0	$	75.0	$	170.0	$	(25.0)	$	(95.0)
Repayment of short-term borrowings	(100.0)		(25.0)		(170.0)		(75.0)		145.0
Issuance of long-term debt	554.0		117.4		604.0		436.6		(486.6)
Repayment of long-term debt	(25.0)		(148.6)		(468.9)		123.6		320.3
Debt issuance costs	(.9)		(.5)		(4.5)		(.4)		4.0
Proceeds from issuance of common stock	88.8		3.4		106.8		85.4		(103.4)
Dividends paid	(171.3)		(166.4)		(160.3)		(4.9)		(6.1)
Repurchase of common stock	(6.7)		—		—		(6.7)		—
Tax withholding on stock-based compensation	(4.2)		(.4)		(3.0)		(3.8)		2.6
Net cash provided by (used in) financing activities	$	384.7	$	(145.1)	$	74.1	$	529.8	$	(219.2)

The increase in cash flows provided by financing activities from 2021 to 2020 was largely the result of increased long-term borrowings for acquisitions at the construction materials and contracting business, and increased long-term borrowings, net of repayments, associated with capital expenditures at the pipeline, electric and natural gas distribution businesses. The construction services business also increased its long-term borrowings as a result of increased working capital needs. In addition, net proceeds from the issuance of common stock under the Company's "at-the-market" offering during 2021 also contributed to the increase in cash flows from financing activities. Partially offsetting these increases were decreased short-term borrowings during 2021 at the natural gas distribution business. Montana-Dakota repaid $50 million of short-term borrowings during the first quarter of 2021 related to short-term borrowings during 2020. Montana-Dakota also issued $50 million of short-term borrowings during the first quarter of 2021 related to financing the higher natural gas purchases, as previously discussed, which was repaid prior to the end of the year.

The increase in cash flows used in financing activities from 2020 to 2019 was largely the result of a decrease in net long-term and short-term debt borrowings in 2020 as compared to 2019 due to lower working capital needs. In addition, the Company had decreased net proceeds of $103.5 million in 2020 due to the absence of common stock issuance under its "at-the-market" offering and 401(k) plan.

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. At December 31, 2021, the pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $38.4 million. Pretax pension income reflected in the Consolidated Statements of Income for the years ended December 31, 2021 and 2020, was $1.7 million and $684,000, respectively. Pretax pension expense reflected in the Consolidated Statements of Income for the year ended December 31, 2019, was $2.5 million. The Company's

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pension income is currently projected to be approximately $2.3 million in 2022. Funding for the pension plans is actuarially determined. The Company has no minimum funding requirements for its defined benefit pension plans for 2022 due to an additional contribution of $20.0 million in 2019, which created prefunding credits to be used in future periods. There were no minimum required contributions for the years ended December 31, 2021 and 2020, and the minimum required contributions for the year ended December 31, 2019, was approximately $4.9 million. For more information on the Company's pension plans, see Item 8 - Note 18.

Capital expenditures

The Company's capital expenditures for 2019 through 2021 and as anticipated for 2022 through 2024 are summarized in the following table.


	Actual*						Estimated
	2019		2020		2021		2022		2023		2024
	(In millions)
Capital expenditures:
Electric	$	99	$	115	$	82	$	165	$	116	$	85
Natural gas distribution	207		193		170		248		232		207
Pipeline	71		62		235		72		159		106
Construction materials and contracting	190		191		418		189		166		172
Construction services	61		84		29		47		42		43
Other	8		3		2		5		4		3
Total capital expenditures	$	636	$	648	$	936	$	726	$	719	$	616

*Capital expenditures for 2021, 2020 and 2019 include noncash transactions such as capital expenditure-related accounts payable, AFUDC and accrual of holdback payments in connection with acquisitions totaling $38.7 million, $(15.7) million and $4.8 million, respectively.

The 2021 capital expenditures include the completed business combinations at the construction materials and contracting segment, as discussed in Item 8 - Note 4, and the North Bakken Expansion project at the pipeline segment. The 2021 capital expenditures were funded by internal sources, equity issuance and borrowings under credit facilities and issuance of commercial paper of the Company's subsidiaries. The Company has included in the estimated capital expenditures for 2022 through 2024 the Wahpeton Expansion and additional growth projects at the pipeline segment and construction of Heskett Unit 4, as previously discussed in Business Segment Financial and Operating Data.

Estimated capital expenditures for the years 2022 through 2024 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 2022 through 2024 will be funded by various sources, including internally generated funds; credit facilities and commercial paper of the Company's subsidiaries, as described later; and issuance of debt and equity securities if necessary.

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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, cash from the issuance of long-term debt and cash from equity markets.

Debt resources

Certain debt instruments of the Company's subsidiaries, including those discussed later, contain restrictive and financial covenants and cross-default provisions. In order to borrow under the debt agreements, 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, 2021. 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, 2021, 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 9.

The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries at December 31, 2021:


Company	Facility	Facility Limit			Amount Outstanding		Letters of Credit			Expiration Date
		(In millions)
Montana-Dakota Utilities Co.	Commercial paper/Revolving credit agreement (a)	$	175.0		$	64.9	$	—		12/19/24
Cascade Natural Gas Corporation	Revolving credit agreement	$	100.0	(b)	$	71.0	$	2.2	(c)	6/7/24
Intermountain Gas Company	Revolving credit agreement	$	85.0	(d)	$	56.5	$	—		6/7/24
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement (e)	$	600.0		$	385.4	$	—		12/19/24

(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 $225.0 million). 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 $110.0 million.

(e)The commercial paper program is 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). There were no amounts outstanding under the revolving credit agreement.

The respective commercial paper programs are supported by revolving credit agreements. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, Montana-Dakota and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements. The commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of certain operations of the Company's subsidiaries. Any borrowings under its commercial paper and revolving credit agreements are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued borrowings.

Total equity as a percent of total capitalization was 55 percent and 58 percent at December 31, 2021 and 2020, respectively. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within 12 months, plus total equity. This ratio is an indicator of how the Company is financing its operations, as well as its financial strength.

Certain of the Company's debt instruments use LIBOR as a benchmark for establishing the applicable interest rate. LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform. These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. The Company has been proactive to anticipate the reform of LIBOR by updating its credit agreements to include language regarding the successor or alternate rate to LIBOR. The Company continues to evaluate the impact the reform will have on its debt instruments and, at this time, does not anticipate a significant impact.

Montana-Dakota 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.

On March 8, 2021, Montana-Dakota entered into a $50.0 million term loan agreement with a LIBOR-based variable interest rate and a maturity date of March 7, 2022. At December 31, 2021, Montana-Dakota had no amount outstanding under the agreement. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments.

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On September 15, 2021, Montana-Dakota entered into a $125.0 million note purchase agreement with maturity dates ranging from September 15, 2051 to September 15, 2061, at a weighted average interest rate of 3.23 percent. On September 15, 2021 and December 15, 2021, Montana-Dakota issued $75.0 million and $50.0 million, respectively, in senior notes under the note purchase agreement. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent.

Centennial Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Historically, downgrades in Centennial's credit ratings have not limited, nor are currently expected to limit, Centennial's ability to access the capital markets. If Centennial 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 Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding.

On December 23, 2021, WBI Energy Transmission entered into a $50.0 million note purchase agreement with a maturity date of December 23, 2041, at an interest rate of 3.67 percent. The agreement contains customary covenants and provisions, including a covenant of WBI Energy Transmission not to permit, at any time, the ratio of total debt to total capitalization to be greater than 55 percent.

Equity Resources

The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The Company may sell such 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. For more information on the Company's equity, see Item 8 - Note 12.

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. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement. As of December 31, 2021, the Company had capacity to issue up to 3.6 million additional shares of common stock under the "at-the-market" offering program. Proceeds from the sale of shares of common stock under the agreement have been and are expected to be used for general corporate purposes, which may include, among other things, working capital, capital expenditures, debt repayment and the financing of acquisitions.

Details of the Company's "at-the-market" offering activity for the years ended December 31 was as follows:


	2021		2020
	(In millions)
Shares issued	2.8		—
Net proceeds *	$	88.8	$	—
Issuance costs	$	1.2	$	—

* Net proceeds were used for capital expenditures.

Dividend restrictions

For information on the Company's dividends and dividend restrictions, see Item 8 - Note 12.

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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 9, 10 and 21. At December 31, 2021, 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)
Long-term debt maturities*	$	148.1	$	716.5	$	318.6	$	1,564.9	$	2,748.1
Estimated interest payments**	98.6		178.7		157.3		835.8		1,270.4
Operating leases	38.6		47.2		19.0		44.0		148.8
Purchase commitments	589.9		342.1		186.1		731.7		1,849.8
	$	875.2	$	1,284.5	$	681.0	$	3,176.4	$	6,017.1

* 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, 2021, 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, 2021, the current portion of asset retirement obligations was $10.6 million and was included in other accrued liabilities on the Consolidated Balance Sheets.

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, 2021, the Company had total liabilities of $468.7 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 11.

Not reflected in the previous table are $1.7 million in uncertain tax positions at December 31, 2021.

The Company has no minimum funding requirements for its defined benefit pension plans for 2022 due to an additional contribution of $20.0 million in 2019.

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 18.

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.

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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 17. 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, 2021, 2020 and 2019, there were no impairment losses recorded. At October 31, 2021, the fair value substantially exceeded the carrying value at all reporting units; therefore, the Company did not perform additional sensitivity analyses to determine what impact changes in estimates would have on the fair value of the reporting units.

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, 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.

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 5 percent to 9 percent in 2021, 4 percent to 8 percent for 2020 and 4 percent to 9 percent for 2019.

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 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 15 percent control premium for the years ended December 31, 2021, 2020 and 2019.

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 used in the five-year forecast 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 and was 1 percent to 3 percent in 2021, 2020 and 2019.

Business combinations

The Company accounts for acquisitions on the Consolidated Financial Statements starting from the date of the acquisition, which is the date that control is obtained. The acquisition method of accounting requires acquired assets and liabilities assumed be recorded at their respective fair values as of the date of the acquisition. The excess of the purchase price over the fair value of the assets acquired and liabilities assumed is recorded as goodwill. The estimation of fair values of acquired assets and liabilities assumed by the Company requires significant judgment and requires various assumptions. Although independent appraisals may be used to assist in the determination of the fair value of certain assets and liabilities, the appraised values may be based on significant estimates provided by management. The amounts and useful lives assigned to depreciable and amortizable assets compared to amounts assigned to goodwill, which is not amortized, can affect the results of operations in the period of and periods subsequent to a business combination.

In determining fair values of acquired assets and liabilities assumed, the Company uses various observable inputs for similar assets or liabilities in active markets and various unobservable inputs, which includes the use of valuation models. Fair values are based on various factors including, but not limited to, age and condition of property, maintenance records, auction values for equipment with similar characteristics, recent sales and listings of comparable properties, data collected from drill holes and other subsurface investigations and geologic data. The Company primarily uses the market and cost approaches in determining the fair value of land and property, plant and equipment. A combination of the market and income approaches are used for aggregate reserves and intangibles, primarily a discounted cash flow model. The Company must develop reasonable and supportable assumptions to evaluate future cash flows. The process is highly subjective and requires a large degree of management judgement. Assumptions used may vary for each specific business combination due to unique circumstances of each transaction. Assumptions may include discount rate, time period, terminal value and growth rate. The values generated from the discounted cash flow model are sensitive to the assumptions used. Inaccurate assumptions can lead to deviations from the values generated.

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There is a measurement period after the acquisition date during which the Company may adjust the amounts recognized for a business combination. Any such adjustments are recorded in the period the adjustment is determined with the corresponding offset to goodwill. These adjustments are typically based on obtaining additional information that existed at the acquisition date regarding the assets acquired and the liabilities assumed. The measurement period ends once the Company has obtained all necessary information that existed as of the acquisition date, but does not extend beyond one year from the date of the acquisition. Once the measurement period has ended, any adjustments to assets acquired or liabilities assumed are recorded in income from continuing operations.

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, 2021 and 2020, the Company's regulatory assets were $476.5 million and $447.9 million, respectively, and regulatory liabilities were $445.1 million and $459.5 million, respectively. At December 31, 2021 and 2020, regulatory assets in recovery were $367.7 million and $324.6 million, respectively, and regulatory assets not in recovery were $108.8 million and $123.3 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, 2021 and 2020, the Company's total construction contract revenue was $3.0 billion and $3.1 billion, respectively.

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.

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The Company's construction contracts generally contain variable consideration including liquidated damages, performance bonuses or incentives, claims, unapproved/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 estimation methods that best predict the most likely amount of consideration the Company expects to be entitled to or expects to incur. The Company 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. 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 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, the rate of compensation increases, 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. Management estimates the rate of compensation increase based on long-term assumed wage increases and the health care cost trend rates are determined by historical and future trends.

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, the rate of compensation increase 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, 2021:


	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, 2021	$	(22.0)	$	24.2	$	(4.0)	$	4.5
Net periodic benefit cost (credit) for 2022	$	.3	$	(.4)	$	(.3)	$	.2
Expected long-term return on plan assets
Net periodic benefit cost (credit) for 2022	$	(1.8)	$	1.8	$	(.5)	$	.5

A 100 basis point change in the assumed health care cost trend rates would have had the following effects at December 31, 2021:


	100 Basis Point Increase		100 Basis Point Decrease
	(In millions)
Service and interest cost components for 2022	$	.2	$	(.1)
Postretirement benefit obligation as of December 31, 2021	$	3.0	$	(2.6)

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 18.

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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.

Non-GAAP Financial Measures

The Business Segment Financial and Operating Data includes financial information prepared in accordance with GAAP, as well as another financial measure, adjusted gross margin, that is considered a non-GAAP financial measure as it relates to the Company's electric and natural gas distribution segments and is intended to be a helpful supplemental financial measure for investors' understanding of the utility segments' operating performance. The Company's management believes that adjusted gross margin and the remaining operating expenses that calculate operating income (loss) are useful in assessing the company's segment performance as management has the ability to influence control over the remaining operating expenses. This non-GAAP financial measure should not be considered as an alternative to, or more meaningful than, GAAP financial measures such as operating income (loss) or net income (loss). The Company's non-GAAP financial measure, adjusted gross margin, is not standardized; therefore, it may not be possible to compare this financial measure with other companies’ gross margin measures having the same or similar names.

In addition to operating revenues and operating expenses, management also uses the non-GAAP financial measure of adjusted gross margin when evaluating the results of operations for the electric and natural gas distribution segments. Adjusted gross margin for the electric and natural gas distribution segments is calculated by adding back adjustments to operating income (loss). These add-back adjustments include: operation and maintenance expense; depreciation, depletion and amortization expense; and certain taxes, other than income. The Company's adjusted gross margin is impacted by fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact adjusted gross margin as a percentage of revenue, they only impact adjusted gross margin if the costs cannot be passed through to customers.

The following information reconciles operating income to adjusted gross margin for the electric segment.


Years ended December 31,	2021		2020		2019
	(In millions)
Operating income	$	66.3	$	63.4	$	64.0
Adjustments:
Operating expenses:
Operation and maintenance	124.9		121.3		125.7
Depreciation, depletion and amortization	66.8		63.0		58.7
Taxes, other than income	16.7		16.8		16.1
Total adjustments	208.4		201.1		200.5
Adjusted gross margin	$	274.7	$	264.5	$	264.5

The following information reconciles operating income to adjusted gross margin for the natural gas distribution segment.


Years ended December 31,	2021		2020		2019
	(In millions)
Operating income	$	89.2	$	73.1	$	69.2
Adjustments:
Operating expenses:
Operation and maintenance	194.1		185.4		185.0
Depreciation, depletion and amortization	86.0		84.6		79.6
Taxes, other than income	25.9		24.6		23.5
Total adjustments	306.0		294.6		288.1
Adjusted gross margin	$	395.2	$	367.7	$	357.3

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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 taking advantage of 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 8 and 9. At December 31, 2021 and 2020, the Company had no outstanding interest rate hedges.

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, 2021.


	2022			2023			2024			2025			2026			Thereafter			Total			Fair Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	148.1		$	77.9		$	60.8		$	177.8		$	140.8		$	1,564.9		$	2,170.3		$	2,413.2
Weighted average interest rate	4.5		%	3.7		%	4.2		%	4.0		%	5.7		%	4.3		%	4.4		%
Variable rate	$	—		$	—		$	577.8		$	—		$	—		$	—		$	577.8		$	577.8
Weighted average interest rate	—		%	—		%	.7		%	—		%	—		%	—		%	.7		%

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, 2021 and 2020, 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

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, 2021. 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, 2021.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.


/s/ David L. Goodin			/s/ Jason L. Vollmer


David L. Goodin			Jason L. Vollmer
President and Chief Executive Officer			Vice President and Chief Financial Officer

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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, 2021 and 2020, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 23, 2022, 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 3 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 as it best depicts the transfer of assets to the customer. Under this method of measuring progress, costs incurred are compared with total estimated costs of the performance obligation and revenues are recorded proportionately to the costs incurred. Ordinarily the Company’s contracts represent a single distinct performance obligation due to the highly interdependent and interrelated nature of the underlying goods or services. For the year ended December 31, 2021, the Company recognized $3.0 billion of construction contract revenue.

Given the judgments necessary to estimate total costs and profit for the performance obligations 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.

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 certain 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.

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•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.

•Compared the transaction prices 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, services, or both were highly interdependent and interrelated.

•Tested the accuracy and completeness of the costs incurred to date for the performance obligation.

•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 20 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.

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.

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•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.


/s/ Deloitte & Touche LLP


Minneapolis, Minnesota
February 23, 2022

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, 2021, 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, 2021, 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, 2021, of the Company and our report dated February 23, 2022, 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 23, 2022

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Consolidated Statements of Income


Years ended December 31,	2021		2020		2019
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline	$	1,390,343	$	1,249,146	$	1,279,304
Non-regulated pipeline, construction materials and contracting, construction services and other	4,290,390		4,283,604		4,057,472
Total operating revenues	5,680,733		5,532,750		5,336,776
Operating expenses:
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline	366,586		353,184		356,132
Non-regulated pipeline, construction materials and contracting, construction services and other	3,712,037		3,675,078		3,539,162
Total operation and maintenance	4,078,623		4,028,262		3,895,294
Purchased natural gas sold	483,118		390,269		421,545
Depreciation, depletion and amortization	299,214		285,100		256,017
Taxes, other than income	211,454		217,253		196,143
Electric fuel and purchased power	74,105		66,941		86,557
Total operating expenses	5,146,514		4,987,825		4,855,556
Operating income	534,219		544,925		481,220
Other income	26,416		26,711		15,812
Interest expense	93,984		96,519		98,587
Income before income taxes	466,651		475,117		398,445
Income taxes	88,920		84,590		63,279
Income from continuing operations	377,731		390,527		335,166
Income (loss) from discontinued operations, net of tax	400		(322)		287
Net income	$	378,131	$	390,205	$	335,453
Earnings per share - basic:
Income from continuing operations	$	1.87	$	1.95	$	1.69
Discontinued operations, net of tax	—		—		—
Earnings per share - basic	$	1.87	$	1.95	$	1.69
Earnings per share - diluted:
Income from continuing operations	$	1.87	$	1.95	$	1.69
Discontinued operations, net of tax	—		—		—
Earnings per share - diluted	$	1.87	$	1.95	$	1.69
Weighted average common shares outstanding - basic	202,076		200,502		198,612
Weighted average common shares outstanding - diluted	202,383		200,571		198,626

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,	2021		2020		2019
	(In thousands)
Net income	$	378,131	$	390,205	$	335,453
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $145, $145 and $(140) in 2021, 2020 and 2019, respectively	446		446		731
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of $1,626, $(2,606) and $(2,012) in 2021, 2020 and 2019, respectively	4,876		(8,395)		(6,151)
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $615, $630 and $476 in 2021, 2020 and 2019, respectively	1,870		1,922		1,486
Postretirement liability adjustment	6,746		(6,473)		(4,665)
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 $(67), $0 and $35 in 2021, 2020 and 2019, respectively	(252)		(1)		134
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $36, $14 and $10 in 2021, 2020 and 2019, respectively	134		52		40
Net unrealized gain (loss) on available-for-sale investments	(118)		51		174
Other comprehensive income (loss)	7,074		(5,976)		(3,760)
Comprehensive income attributable to common stockholders	$	385,205	$	384,229	$	331,693

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Balance Sheets


December 31,		2021		2020
Assets	(In thousands, except shares and per share amounts)
Current assets:
Cash and cash equivalents		$	54,161	$	59,547
Receivables, net		946,741		873,986
Inventories		335,609		291,167
Current regulatory assets		118,691		68,527
Prepayments and other current assets		95,741		44,120
Total current assets		1,550,943		1,337,347
Noncurrent assets:
Property, plant and equipment		8,972,849		8,300,770
Less accumulated depreciation, depletion and amortization		3,216,461		3,133,831
Net property, plant and equipment		5,756,388		5,166,939
Goodwill		765,386		714,963
Other intangible assets, net		22,578		25,496
Regulatory assets		357,851		379,381
Investments		175,476		165,022
Operating lease right-of-use assets		124,138		120,113
Other		157,675		144,111
Total noncurrent assets		7,359,492		6,716,025
Total assets		$	8,910,435	$	8,053,372
Liabilities and Stockholders' Equity
Current liabilities:
Short-term borrowings		$	—	$	50,000
Long-term debt due within one year		148,053		1,555
Accounts payable		478,933		426,264
Taxes payable		80,372		88,844
Dividends payable		44,229		42,611
Accrued compensation		81,904		90,629
Operating lease liabilities due within one year		35,368		33,655
Regulatory liabilities due within one year		16,303		31,450
Other accrued liabilities		207,078		198,514
Total current liabilities		1,092,240		963,522
Noncurrent liabilities:
Long-term debt		2,593,847		2,211,575
Deferred income taxes		591,962		516,098
Asset retirement obligations		458,061		440,356
Regulatory liabilities		428,790		428,075
Operating lease liabilities		89,253		86,868
Other		273,408		327,773
Total noncurrent liabilities		4,435,321		4,010,745
Commitments and contingencies
Stockholders' equity:
Common stock Authorized - 500,000,000 shares, $1.00 par value Shares issued - 203,889,661 at December 31, 2021 and 201,061,198 at December 31, 2020		203,889		201,061
Other paid-in capital		1,461,205		1,371,385
Retained earnings		1,762,410		1,558,363
Accumulated other comprehensive loss		(41,004)		(48,078)
Treasury stock at cost - 538,921 shares		(3,626)		(3,626)
Total stockholders' equity		3,382,874		3,079,105
Total liabilities and stockholders' equity		$	8,910,435	$	8,053,372

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Equity


Years ended December 31, 2021, 2020 and 2019
				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, 2018	196,564,907	$	196,565	$	1,248,576	$	1,163,602	$	(38,342)	(538,921)	$	(3,626)		$	2,566,775
Net income	—	—		—		335,453		—		—	—			335,453
Other comprehensive loss	—	—		—		—		(3,760)		—	—			(3,760)
Dividends declared on common stock	—	—		—		(162,408)		—		—	—			(162,408)
Employee stock-based compensation	—	—		7,353		—		—		—	—			7,353
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	246,214	246		(3,261)		—		—		—	—			(3,015)
Issuance of common stock	4,111,669	4,112		102,736		—		—		—	—			106,848
At December 31, 2019	200,922,790	200,923		1,355,404		1,336,647		(42,102)		(538,921)	(3,626)			2,847,246
Net Income	—	—		—		390,205		—		—	—			390,205
Other comprehensive loss	—	—		—		—		(5,976)		—	—			(5,976)
Dividends declared on common stock	—	—		—		(168,489)		—		—	—			(168,489)
Employee stock-based compensation	—	—		13,096		—		—		—	—			13,096
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	26,406	26		(388)		—		—		—	—			(362)
Issuance of common stock	112,002	112		3,273		—		—		—	—			3,385
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

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,	2021		2020		2019
	(In thousands)
Operating activities:
Net income	$	378,131	$	390,205	$	335,453
Income (loss) from discontinued operations, net of tax	400		(322)		287
Income from continuing operations	377,731		390,527		335,166
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	299,214		285,100		256,017
Deferred income taxes	60,250		(1,801)		63,415
Provision for credit losses	1,085		10,576		7,864
Amortization of debt issuance costs	1,333		2,162		1,330
Employee stock-based compensation costs	14,709		13,096		7,353
Pension & postretirement benefit plan net periodic benefit cost (credit)	(4,900)		(3,001)		703
Unrealized gains on investments	(7,728)		(14,563)		(11,445)
Gains on sales of assets	(13,056)		(15,350)		(15,479)
Changes in current assets and liabilities, net of acquisitions:
Receivables	(60,024)		(2,780)		(112,238)
Inventories	(42,302)		(7,221)		9,331
Other current assets	(71,964)		31,601		(38,283)
Accounts payable	15,247		15,955		30,079
Other current liabilities	(17,650)		35,591		51,278
Pension & postretirement benefit plan contributions	(476)		(434)		(25,613)
Other noncurrent changes	(55,367)		30,291		(17,662)
Net cash provided by continuing operations	496,102		769,749		541,816
Net cash provided by (used in) discontinued operations	(325)		(1,375)		464
Net cash provided by operating activities	495,777		768,374		542,280
Investing activities:
Capital expenditures	(659,425)		(558,007)		(576,065)
Acquisitions, net of cash acquired	(237,718)		(105,979)		(55,597)
Net proceeds from sale or disposition of property and other	15,238		35,557		29,812
Investments	(3,973)		(1,814)		(2,011)
Net cash used in investing activities	(885,878)		(630,243)		(603,861)
Financing activities:
Issuance of short-term borrowings	50,000		75,000		170,000
Repayment of short-term borrowings	(100,000)		(25,000)		(170,000)
Issuance of long-term debt	554,027		117,450		603,969
Repayment of long-term debt	(24,979)		(148,634)		(468,917)
Debt issuance costs	(918)		(477)		(4,537)
Proceeds from issuance of common stock	88,767		3,385		106,848
Dividends paid	(171,354)		(166,405)		(160,256)
Repurchase of common stock	(6,701)		—		—
Tax withholding on stock-based compensation	(4,127)		(362)		(3,015)
Net cash provided by (used in) financing activities	384,715		(145,043)		74,092
Increase (decrease) in cash and cash equivalents	(5,386)		(6,912)		12,511
Cash and cash equivalents - beginning of year	59,547		66,459		53,948
Cash and cash equivalents - end of year	$	54,161	$	59,547	$	66,459

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 materials and contracting, construction services and other. The electric and natural gas distribution businesses, as well as a portion of the pipeline business, are regulated. Construction materials and contracting, construction services and the other businesses, as well as a portion of the pipeline business, are non-regulated. For further descriptions of the Company's businesses, see Note 17.

Beginning in March 2020, governmental restrictions and guidelines implemented to control the spread of COVID-19 reduced commercial and interpersonal activity throughout the Company's areas of operation. Most of the Company's products and services are considered essential to America and its communities and, as a result, operations have generally continued through the COVID-19 pandemic and reopening of the country's economy. The Company has assessed the impacts of the COVID-19 pandemic on its results of operations for the years ended December 31, 2021 and 2020, and determined there were no material adverse impacts.

The assets and liabilities of the Company's discontinued operations have been classified as held for sale and are included in prepayments and other current assets, noncurrent assets - other and other accrued liabilities on the Consolidated Balance Sheets and are not material to the financial statements for any period presented. The results and supporting activities are shown in income (loss) from discontinued operations on the Consolidated Statements of Income. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations.

In 2021, the Company made changes to the presentation of the Consolidated Statements of Cash Flows to provide further clarity on the sources and uses of net cash provided by operating activities and net cash provided by (used in) financing activities. Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not impact total net cash provided by operating activities or net cash provided by (used in) financing activities for the years ended December 31, 2020 and 2019.

Management has also evaluated the impact of events occurring after December 31, 2021, up to the date of issuance of these consolidated financial statements on February 23, 2022, 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 17.

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 19 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; fair values of acquired assets and liabilities under the acquisition method of accounting; aggregate reserves; 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 2018-14 - Changes to the Disclosure Requirements for Defined Benefit Plans	In August 2018, the FASB issued guidance on modifying the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans as part of the disclosure framework project. The guidance removed disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and added disclosure requirements identified as relevant. The guidance added, among other things, the requirement to include an explanation for significant gains and losses related to changes in benefit obligations for the period. The guidance removed, among other things, the disclosure requirement to disclose the amount of net periodic benefit costs to be amortized over the next fiscal year from accumulated other comprehensive income (loss) and the effects a one percentage point change in assumed health care cost trend rates will have on certain benefit components.	January 1, 2021	The Company determined the guidance did not materially impact its consolidated financial statement disclosures.
ASU 2019-12 - Simplifying the Accounting for Income Taxes	In December 2019, the FASB issued guidance on simplifying the accounting for income taxes by removing certain exceptions in ASC 740 and providing simplification amendments. The guidance removed exceptions on intraperiod tax allocations and reporting and provided simplification on accounting for franchise taxes, tax basis goodwill and tax law changes.	January 1, 2021	The Company determined the guidance did not materially impact its results of operations, financial position, cash flows or disclosures.
Recently issued accounting standards not yet adopted
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 and will continue through December 31, 2022	The Company has updated its credit agreements to include language regarding the successor or alternate rate to LIBOR, and a review of other contracts and agreements is on-going. The Company does not expect the guidance to have a material impact on its results of operations, financial position, cash flows or disclosures.
ASU 2021-10 - Government Assistance	In November 2021, the FASB issued guidance on modifying the disclosure requirements to increase the transparency of government assistance including disclosure of the types of assistance, an entity's accounting for the assistance and the effect of the assistance on an entity's financial statements.	January 1, 2022	The Company is currently evaluating the impact the guidance will have on its disclosures for the year ended December 31, 2022.

Cash and cash equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

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/

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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 materials and contracting segment generates revenue from contracting services and construction materials sales. This segment focuses on the vertical integration of its contracting services with its construction materials to support the aggregate-based product lines. This segment provides 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 integrating a set of services and related construction materials into a single project to create a distinct bundle of goods and services, which the Company evaluates to determine whether a separate performance obligation exists. The transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable consideration that exist in this segment's contracts include liquidated damages; performance bonuses or incentives and penalties; claims; unapproved/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 estimation methods that best predict the most likely amount of consideration the Company expects to be entitled to or expects to incur. The Company 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. 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. Revenue is recognized over time using an input method based on the cost-to-cost measure of progress on a project. This is the preferred method of measuring revenue because the costs incurred have been determined to represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. This segment also sells construction materials to third parties and internal customers. The contract for material sales is the use of a sales order or an invoice, which includes the pricing and payment terms. All material contracts contain 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 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 evaluates to determine whether a separate performance obligation exists. The transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable consideration that exist in this segment's contracts include claims, unapproved/unpriced change orders, bonuses, incentives, penalties and liquidated damages. 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 estimation methods that best predict the most likely amount of consideration the Company expects to be entitled to or expects to incur. The Company 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. The Company updates its

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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. Revenue is recognized over time using the input method based on the measurement of progress on a project. The input method is the preferred method of measuring revenue because the costs incurred have been determined to represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. 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.

Business combinations

For all business combinations, the Company preliminarily allocates the purchase price of the acquisitions to the assets acquired and liabilities assumed based on their estimated fair values as of the acquisition dates and are considered provisional until final fair values are determined or the measurement period has passed. The Company expects to record adjustments as it accumulates the information needed to estimate the fair value of assets acquired and liabilities assumed, including working capital balances, estimated fair value of identifiable intangible assets, property, plant and equipment, total consideration and goodwill. The excess of the purchase price over the aggregate fair values is recorded as goodwill. The Company calculated the fair value of the assets acquired in 2021 and 2020 using a market or cost approach (or a combination of both). Fair values for some of the assets were determined based on Level 3 inputs including estimated future cash flows, discount rates, growth rates, sales projections, retention rates and terminal values, all of which require significant management judgment and are susceptible to change. The final fair value of the net assets acquired may result in adjustments to the assets and liabilities, including goodwill, and will be made as soon as practical, but no later than 12 months from the respective acquisition dates. Any subsequent measurement period adjustments are not expected to have a material impact on the Company's results of operations.

Receivables and allowance for expected credit losses

Receivables consist primarily of trade receivables from the sale of goods and services, which are recorded at the invoiced amount, and contract assets, net of expected credit losses. For more information on contract assets, see Note 3. 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 $44.8 million and $43.9 million at December 31, 2021 and 2020, 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.

The Company conducted additional analysis of its receivables and allowance for expected credit losses due to the impacts of COVID-19. As more customer balances entered arrears, further analysis supported increasing the uncollectible factors used in determining the expected credit losses of certain segments during 2020. During 2021, certain segments continued to experience balances in arrears higher than historical levels, which supported the continued use of increased uncollectible factors, while other segments experienced balances in arrears returning to historical levels alleviating the need for certain associated credit loss estimates. Management has reviewed the balance reserved through the allowance for expected credit losses and believes it is reasonable.

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Details of the Company's expected credit losses were as follows:


	Electric		Natural gas distribution		Pipeline		Construction materials and contracting		Construction services		Total
	(In thousands)
At January 1, 2020	$	328	$	1,056	$	—	$	5,357	$	1,756	$	8,497
Current expected credit loss provision*	1,517		3,187		2		1,447		4,832		10,985
Less write-offs charged against the allowance	1,289		2,511		—		640		866		5,306
Credit loss recoveries collected	343		839		—		—		—		1,182
At December 31, 2020	899		2,571		2		6,164		5,722		15,358
Current expected credit loss provision*	1,099		2,188		—		68		(2,250)		1,105
Less write-offs charged against the allowance	2,139		4,072		—		826		1,032		8,069
Credit loss recoveries collected	410		819		—		—		93		1,322
At December 31, 2021	$	269	$	1,506	$	2	$	5,406	$	2,533	$	9,716

*Includes impacts from businesses acquired.

Receivables also consist of accrued unbilled revenue representing revenues recognized in excess of amounts billed. Accrued unbilled revenue at MDU Energy Capital was $144.9 million and $94.0 million at December 31, 2021 and 2020, respectively.

Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows:


	2021		2020
	(In thousands)
Short-term retainage*	$	70,600	$	100,054
Long-term retainage**	10,742		2,761
Total retainage	$	81,342	$	102,815

* Expected to be paid within 12 months or less and included in receivables, net.

** Included in noncurrent assets - other.

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:


	2021		2020
	(In thousands)
Aggregates held for resale	$	184,363	$	175,782
Asphalt oil	57,002		28,238
Materials and supplies	30,629		25,142
Merchandise for resale	28,501		21,087
Natural gas in storage (current)	18,867		21,919
Other	16,247		18,999
Total	$	335,609	$	291,167

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 $47.5 million at December 31, 2021 and 2020.

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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 construction projects associated with its other operations. The amount of AFUDC for the years ended December 31 was as follows:


	2021		2020		2019
	(In thousands)
AFUDC - borrowed	$	2,833	$	2,640	$	2,807
AFUDC - equity	$	6,961	$	1,270	$	698

Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method. 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

The Company reviews the carrying values of its long-lived assets, excluding goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. 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 significant impairment losses were recorded in 2021, 2020 or 2019. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.

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.

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 refundable through rate adjustments were $6.7 million and $18.6 million at December 31, 2021 and 2020, respectively, which was included in regulatory liabilities due within one year on the Consolidated Balance Sheets. Natural gas costs recoverable through rate adjustments were $91.6 million and $64.0 million at December 31, 2021 and 2020, respectively, which was included in current regulatory assets and noncurrent assets - regulatory assets on the Consolidated Balance Sheets.

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 17. 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, 2021, 2020 and 2019, there were no impairment losses recorded. The Company performed its annual goodwill impairment test in the fourth quarter of 2021 and determined the fair value substantially exceeded the carrying value at all reporting units at October 31, 2021.

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Investments

The Company's investments include the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. The Company measures its investment in the insurance contract 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 8 and 18.

Joint ventures

The Company accounts for unconsolidated joint ventures using either the equity method or proportionate consolidation. The Company currently holds interests between 33 percent and 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 $14.7 million and $69.7 million of revenue for the years ended December 31, 2021 and 2020, respectively, and $4.7 million and $20.6 million of operating income for the years ended December 31, 2021 and 2020, respectively. At December 31, 2021 and 2020, the Company had receivables from these joint ventures of $1.2 million and $1.8 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 at December 31, 2021 and 2020, were a net asset of $1.3 million and $425,000, respectively. In 2021 and 2020, the Company recognized income (loss) from equity method joint ventures of $892,000 and $(32,000), 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.

During 2021 and 2020, the Company entered into commodity price derivative contracts securing the purchase of 450,000 MMBtu and 1.4 million MMBtu of natural gas, respectively.

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.

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, which only has a service condition. This method recognizes stock compensation expense on a straight-line basis over the

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requisite service period for the entire award. The Company recognizes 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 is adjusted based upon the determination of the potential achievement of the performance target at each reporting date. The Company recognizes compensation expense related to performance awards with market-based performance metrics on a straight-line basis over the requisite service period.

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. 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:


	2021	2020	2019
	(In thousands)
Weighted average common shares outstanding - basic	202,076	200,502	198,612
Effect of dilutive performance share awards	307	69	14
Weighted average common shares outstanding - diluted	202,383	200,571	198,626
Shares excluded from the calculation of diluted earnings per share	—	164	164

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 a regulatory liability and are included in other 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.

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.

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Note 3 - Revenue from Contracts with Customers

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.

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 17.


Year ended December 31, 2021	Electric		Natural gas distribution		Pipeline		Construction materials and contracting		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
Contracting services	—		—		—		1,017,471		—		—		1,017,471
Construction materials	—		—		—		1,712,503		—		—		1,712,503
Intrasegment eliminations	—		—		—		(501,044)		—		—		(501,044)
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		13,714		81,407
Intersegment eliminations	(543)		(576)		(59,678)		(624)		(2,555)		(13,630)		(77,606)
Revenues from contracts with customers	355,564		962,369		82,670		2,228,306		1,999,495		84		5,628,488
Revenues out of scope	(6,525)		8,995		188		—		49,587		—		52,245
Total external operating revenues	$	349,039	$	971,364	$	82,858	$	2,228,306	$	2,049,082	$	84	$	5,680,733


Year ended December 31, 2020	Electric		Natural gas distribution		Pipeline		Construction materials and contracting		Construction services		Other		Total
	(In thousands)
Residential utility sales	$	122,663	$	476,388	$	—	$	—	$	—	$	—	$	599,051
Commercial utility sales	131,477		277,873		—		—		—		—		409,350
Industrial utility sales	36,744		26,243		—		—		—		—		62,987
Other utility sales	6,634		—		—		—		—		—		6,634
Natural gas transportation	—		45,546		111,686		—		—		—		157,232
Natural gas gathering	—		—		4,865		—		—		—		4,865
Natural gas storage	—		—		14,918		—		—		—		14,918
Contracting services	—		—		—		1,069,665		—		—		1,069,665
Construction materials	—		—		—		1,659,152		—		—		1,659,152
Intrasegment eliminations	—		—		—		(550,815)		—		—		(550,815)
Electrical & mechanical specialty contracting	—		—		—		—		1,397,124		—		1,397,124
Transmission & distribution specialty contracting	—		—		—		—		649,486		—		649,486
Other	32,452		10,753		12,216		—		1,541		11,903		68,865
Intersegment eliminations	(491)		(534)		(58,531)		(417)		(5,038)		(11,958)		(76,969)
Revenues from contracts with customers	329,479		836,269		85,154		2,177,585		2,043,113		(55)		5,471,545
Revenues out of scope	2,059		11,382		192		—		47,572		—		61,205
Total external operating revenues	$	331,538	$	847,651	$	85,346	$	2,177,585	$	2,090,685	$	(55)	$	5,532,750

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Year ended December 31, 2019	Electric		Natural gas distribution		Pipeline		Construction materials and contracting		Construction services		Other		Total
	(In thousands)
Residential utility sales	$	125,369	$	483,452	$	—	$	—	$	—	$	—	$	608,821
Commercial utility sales	141,596		296,835		—		—		—		—		438,431
Industrial utility sales	37,765		26,895		—		—		—		—		64,660
Other utility sales	7,408		—		—		—		—		—		7,408
Natural gas transportation	—		45,449		101,665		—		—		—		147,114
Natural gas gathering	—		—		9,164		—		—		—		9,164
Natural gas storage	—		—		11,708		—		—		—		11,708
Contracting services	—		—		—		1,088,633		—		—		1,088,633
Construction materials	—		—		—		1,627,833		—		—		1,627,833
Intrasegment eliminations	—		—		—		(525,749)		—		—		(525,749)
Electrical & mechanical specialty contracting	—		—		—		—		1,266,196		—		1,266,196
Transmission & distribution specialty contracting	—		—		—		—		531,882		—		531,882
Other	35,574		12,726		17,687		—		131		16,551		82,669
Intersegment eliminations	—		—		(56,252)		(1,066)		(3,370)		(16,461)		(77,149)
Revenues from contracts with customers	347,712		865,357		83,972		2,189,651		1,794,839		90		5,281,621
Revenues out of scope	4,013		(135)		220		—		51,057		—		55,155
Total external operating revenues	$	351,725	$	865,222	$	84,192	$	2,189,651	$	1,845,896	$	90	$	5,336,776

Presented in the previous tables are intrasegment revenues within the construction materials and contracting segment to highlight the focus on vertical integration as this segment sells materials to both third parties and internal customers. Due to consolidation requirements, these revenues must be eliminated against construction materials to arrive at the external operating revenue total for the segment.

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, 2021		December 31, 2020		Change		Location on Consolidated Balance Sheets
	(In thousands)
Contract assets	$	125,742	$	104,345	$	21,397	Receivables, net
Contract liabilities - current	(179,140)		(158,603)		(20,537)		Accounts payable
Contract liabilities - noncurrent	(118)		(52)		(66)		Noncurrent liabilities - other
Net contract liabilities	$	(53,516)	$	(54,310)	$	794


	December 31, 2020		December 31, 2019		Change		Location on Consolidated Balance Sheets
	(In thousands)
Contract assets	$	104,345	$	109,078	$	(4,733)	Receivables, net
Contract liabilities - current	(158,603)		(142,768)		(15,835)		Accounts payable
Contract liabilities - noncurrent	(52)		(19)		(33)		Noncurrent liabilities - other
Net contract liabilities	$	(54,310)	$	(33,709)	$	(20,601)

The Company recognized $155.0 million and $138.2 million in revenue for the years ended December 31, 2021 and 2020, respectively, which was previously included in contract liabilities at December 31, 2020 and 2019, respectively.

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The Company recognized a net increase in revenues of $66.3 million and $58.8 million for the years ended December 31, 2021 and 2020, respectively, from performance obligations satisfied in prior periods.

Remaining performance obligations

The remaining performance obligations, also referred to as backlog, at the construction materials and contracting and construction services segments 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 firm storage contracts included in the remaining performance obligations have weighted average remaining durations of less than five and one years, respectively.

At December 31, 2021, the Company's remaining performance obligations were $2.5 billion. The Company expects to recognize the following revenue amounts in future periods related to these remaining performance obligations: $1.8 billion within the next 12 months or less; $278.6 million within the next 13 to 24 months; and $411.9 million in 25 months or more.

Note 4 - Business Combinations

The following acquisitions were accounted for as business combinations in accordance with ASC 805 - Business Combinations. The results of the business combinations have been included in the Company's Consolidated Financial Statements beginning on the acquisition date. Pro forma financial amounts reflecting the effects of the business combinations are not presented, as none of these business combinations, individually or in the aggregate, were material to the Company's financial position or results of operations.

The acquisitions are also subject to customary adjustments based on, among other things, the amount of cash, debt and working capital in the business as of the closing date. The amounts included in the Consolidated Balance Sheets for these adjustments are considered provisional until final settlement has occurred.

In 2021 and 2020, the construction materials and contracting segment's acquisitions included:

•Baker Rock Resources and Oregon Mainline Paving, two premier construction materials companies located around the Portland, Oregon metro area, acquired in November 2021. At December 31, 2021, the purchase price allocation was preliminary and will be finalized within 12 months of the acquisition date.

•Mt. Hood Rock, a construction aggregates business in Oregon, acquired in April 2021. At December 31, 2021, the purchase price allocation was preliminary and will be finalized within 12 months of the acquisition date.

•The assets of McMurry Ready-Mix Co., an aggregates and concrete supplier in Wyoming, acquired in December 2020. In the third quarter of 2021, the Company finalized the provisional accounting and recorded an immaterial measurement period adjustment.

•The assets of Oldcastle Infrastructure Spokane, a prestressed-concrete business in Washington, acquired in February 2020. As of December 31, 2020, the purchase price adjustments had been settled with no material adjustments to the provisional accounting.

In February 2020, the construction services segment acquired PerLectric, Inc., an electrical construction company in Virginia. As of March 31, 2021, the purchase price adjustments had been settled with no material adjustments to the provisional accounting.

The total purchase price for acquisitions that occurred in 2021 was $236.1 million, subject to certain adjustments, with cash acquired totaling $900,000. The purchase price includes consideration paid of $235.2 million. The amounts allocated to the aggregated assets acquired and liabilities assumed during 2021 were as follows: $17.0 million to current assets; $179.8 million to property, plant and equipment; $50.6 million to goodwill; $2.2 million to other intangible assets; $8.7 million to current liabilities; $2.5 million to noncurrent liabilities - other and $3.2 million to deferred tax liabilities. The Company issued debt to finance these acquisitions.

The total purchase price for acquisitions that occurred in 2020 was $110.2 million, subject to certain adjustments, with cash acquired totaling $1.7 million. The purchase price includes consideration paid of $106.0 million and $2.5 million of indemnity holdback liabilities. The amounts allocated to the aggregated assets acquired and liabilities assumed during 2020 were as follows: $54.8 million to current assets; $27.1 million to property, plant and equipment; $33.6 million to goodwill; $19.0 million to other intangible assets; $22.6 million to current liabilities; $300,000 to noncurrent liabilities - other and $1.4 million to asset retirement obligations. The $2.5 million indemnity holdback liability related to 2020 acquisitions was paid in 2021. The Company issued debt to finance these acquisitions.

Costs incurred for acquisitions are included in operation and maintenance expense on the Consolidated Statements of Income and were not material for the years ended December 31, 2021, 2020 and 2019.

MDU Resources Group, Inc. Form 10-K 83

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Note 5 - Property, Plant and Equipment

Property, plant and equipment at December 31 was as follows:


	2021		2020		Weighted Average Depreciable Life in Years
	(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation	$	1,056,632	$	1,133,390	48
Distribution	474,037		464,442		47
Transmission	562,080		524,155		65
Construction in progress	62,781		61,766		—
Other	140,117		139,650		14
Natural gas distribution:
Distribution	2,427,779		2,302,121		50
Transmission	107,721		104,695		60
Storage	34,997		33,014		39
General	197,653		198,211		14
Construction in progress	21,741		16,836		—
Other	225,272		213,976		14
Pipeline:
Transmission	673,344		665,567		46
Storage	57,670		52,632		53
Construction in progress	263,640		46,690		—
Other	50,477		49,640		17
Non-regulated:
Pipeline:
Construction in progress	18		4		—
Other	6,719		7,164		10
Construction materials and contracting:
Land	149,066		132,948		—
Buildings and improvements	149,262		130,417		21
Machinery, vehicles and equipment	1,414,260		1,284,604		12
Construction in progress	50,425		23,803		—
Aggregate reserves	584,683		456,704		*
Construction services:
Land	6,513		7,218		—
Buildings and improvements	39,039		41,674		24
Machinery, vehicles and equipment	166,739		163,080		7
Other	13,467		8,824		2
Other:
Land	2,648		2,648		—
Other	34,069		34,897		7

Less accumulated depreciation, depletion and amortization	3,216,461		3,133,831
Net property, plant and equipment	$	5,756,388	$	5,166,939

*Depleted on the units-of-production method based on recoverable aggregate reserves.

84 MDU Resources Group, Inc. Form 10-K

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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	*	2021		2020
			(In thousands)
Regulatory assets:
Current:
Natural gas costs recoverable through rate adjustments	Up to 1 year		$	86,371	$	42,481
Decoupling	Up to 1 year		9,131		703
Conservation programs	Up to 1 year		8,225		7,117
Cost recovery mechanisms	Up to 1 year		4,536		10,645
Other	Up to 1 year		10,428		7,581
			118,691		68,527
Noncurrent:
Pension and postretirement benefits	**		142,681		155,942
Plant costs/asset retirement obligations	Over plant lives		63,116		71,740
Plant to be retired	-		50,070		65,919
Cost recovery mechanisms	Up to 10 years		44,870		16,245
Manufactured gas plant sites remediation	-		26,053		26,429
Taxes recoverable from customers	Over plant lives		12,339		10,785
Natural gas costs recoverable through rate adjustments	Up to 2 years		5,186		21,539
Long-term debt refinancing costs	Up to 39 years		3,794		4,426
Other	Up to 17 years		9,742		6,356
			357,851		379,381
Total regulatory assets			$	476,542	$	447,908
Regulatory liabilities:
Current:
Natural gas costs refundable through rate adjustments	Up to 1 year		$	6,700	$	18,565
Taxes refundable to customers	Up to 1 year		3,841		3,557
Electric fuel and purchased power deferral	Up to 1 year		—		3,667
Other	Up to 1 year		5,762		5,661
			16,303		31,450
Noncurrent:
Taxes refundable to customers	Over plant lives		215,421		227,850
Plant removal and decommissioning costs	Over plant lives		168,152		167,171
Pension and postretirement benefits	**		20,434		16,989
Other	Up to 20 years		24,783		16,065
			428,790		428,075
Total regulatory liabilities			$	445,093	$	459,525
Net regulatory position			$	31,449	$	(11,617)

*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.

As of December 31, 2021 and 2020, approximately $296.6 million and $332.5 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, accelerated depreciation on plant retirement and the estimated future cost of manufactured gas plant site remediation.

In February 2021, a prolonged period of unseasonably cold temperatures in the central United States significantly increased the demand for electric and natural gas services and contributed to increased market prices. Overall, Montana-Dakota and Great Plains incurred approximately $44.0 million in increased natural gas costs in order to maintain services for its customers. These extraordinary natural gas costs were recorded as regulatory assets as they are expected to be recovered from customers. Montana-Dakota and Great Plains have received approval for the recovery of purchased gas adjustments related to the cold-weather event in all jurisdictions impacted, including out-of-cycle purchased gas adjustment requests in most jurisdictions. For a discussion of the Company's most recent cases by jurisdiction, see Note 20.

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In 2019, the Company experienced increased natural gas costs in Washington from the rupture of the Enbridge pipeline in Canada in late 2018. As a result, the Company requested, and the WUTC approved, recovery of the balance of natural gas costs recoverable related to this period of time over three years rather than its normal one-year recovery period.

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. The first unit ceased operations on March 31, 2021, and the Company subsequently began amortizing plant retirement and closure costs related to this facility. During 2021, the Company received approval from the NDPSC and the SDPUC to offset the savings associated with the cessation of operations of this unit with the amortization of the deferred regulatory assets and moved the costs being recovered for this facility from plant retirement to cost recovery mechanisms in the previous table. The two remaining units are being retired during the first quarter of 2022. The Company expects to recover the regulatory assets related to the plant retirements in future rates.

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 - Goodwill and Other Intangible Assets

The changes in the carrying amount of goodwill were as follows:


	Balance at January 1, 2021		Goodwill Acquired During the Year		Measurement Period Adjustments		Balance at December 31, 2021
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	—	$	345,736

Construction materials and contracting	226,003		50,640		(217)		276,426
Construction services	143,224		—		—		143,224
Total	$	714,963	$	50,640	$	(217)	$	765,386


	Balance at January 1, 2020		Goodwill Acquired During the Year		Measurement Period Adjustments		Balance at December 31, 2020
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	—	$	345,736

Construction materials and contracting	217,234		8,778		(9)		226,003
Construction services	118,388		24,436		400		143,224
Total	$	681,358	$	33,214	$	391	$	714,963

Other amortizable intangible assets at December 31 were as follows:


	2021		2020
	(In thousands)
Customer relationships	$	29,740	$	28,836
Less accumulated amortization	10,650		6,887
	19,090		21,949
Noncompete agreements	4,591		3,941
Less accumulated amortization	2,856		2,309
	1,735		1,632
Other	12,601		12,927
Less accumulated amortization	10,848		11,012
	1,753		1,915
Total	$	22,578	$	25,496

The previous tables include goodwill and intangible assets associated with the business combinations completed during 2021 and 2020. For more information related to these business combinations, see Note 4.

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Amortization expense for amortizable intangible assets for the years ended December 31, 2021, 2020 and 2019, was $5.1 million, $9.0 million and $2.4 million, respectively. The amounts of estimated amortization expense for identifiable intangible assets as of December 31, 2021, were:


	2022		2023		2024		2025		2026		Thereafter
	(In thousands)
Amortization expense	$	4,928	$	4,578	$	4,308	$	2,314	$	1,693	$	4,757

Note 8 - 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 plans for 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 $109.6 million and $100.1 million at December 31, 2021 and 2020, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized gains on these investments for the years ended December 31, 2021, 2020 and 2019, were $7.2 million, $13.1 million and $13.2 million, respectively. 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.

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, 2021	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(In thousands)
Mortgage-backed securities	$	8,702	$	51	$	47	$	8,706
U.S. Treasury securities	2,407		—		11		2,396
Total	$	11,109	$	51	$	58	$	11,102


December 31, 2020	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(In thousands)
Mortgage-backed securities	$	9,799	$	156	$	9	$	9,946
U.S. Treasury securities	1,386		—		5		1,381
Total	$	11,185	$	156	$	14	$	11,327

The Company's assets measured at fair value on a recurring basis were as follows:


	Fair Value Measurements at December 31, 2021, 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, 2021
	(In thousands)
Assets:
Money market funds	$	—	$	10,190	$	—	$	10,190
Insurance contract*	—		109,603		—		109,603
Available-for-sale securities:
Mortgage-backed securities	—		8,706		—		8,706
U.S. Treasury securities	—		2,396		—		2,396
Total assets measured at fair value	$	—	$	130,895	$	—	$	130,895

*The insurance contract invests approximately 61 percent in fixed-income investments, 17 percent in common stock of large-cap companies, 8 percent in common stock of mid-cap companies, 7 percent in common stock of small-cap companies, 5 percent in target date investments and 2 percent in cash equivalents.

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	Fair Value Measurements at December 31, 2020, 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, 2020
	(In thousands)
Assets:
Money market funds	$	—	$	8,917	$	—	$	8,917
Insurance contract*	—		100,104		—		100,104
Available-for-sale securities:
Mortgage-backed securities	—		9,946		—		9,946
U.S. Treasury securities	—		1,381		—		1,381
Total assets measured at fair value	$	—	$	120,348	$	—	$	120,348

*The insurance contract invests approximately 57 percent in fixed-income investments, 18 percent in common stock of large-cap companies, 9 percent in common stock of mid-cap companies, 9 percent in common stock of small-cap companies, 5 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 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 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 performed a fair value assessment of the assets acquired and liabilities assumed in the business combinations that occurred during 2021 and 2020. For more information on these Level 2 and Level 3 fair value measurements, see Notes 2 and 4.

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:


	2021		2020
	(In thousands)
Carrying Amount	$	2,741,900	$	2,213,130
Fair Value	$	2,984,866	$	2,537,289

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

88 MDU Resources Group, Inc. Form 10-K

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Note 9 - Debt

The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries:


Company	Facility	Facility Limit			Amount Outstanding at December 31, 2021		Amount Outstanding at December 31, 2020		Letters of Credit at December 31, 2021			Expiration Date
		(In millions)
Montana-Dakota Utilities Co.	Commercial paper/Revolving credit agreement (a)	$	175.0		$	64.9	$	87.7	$	—		12/19/24
Cascade Natural Gas Corporation	Revolving credit agreement	$	100.0	(b)	$	71.0	$	54.0	$	2.2	(c)	6/7/24
Intermountain Gas Company	Revolving credit agreement	$	85.0	(d)	$	56.5	$	41.9	$	—		6/7/24
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement (e)	$	600.0		$	385.4	$	37.9	$	—		12/19/24

(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 $110.0 million.

Short-term debt

Montana-Dakota On March 8, 2021, Montana-Dakota entered into a $50.0 million term loan agreement with a LIBOR-based variable interest rate and a maturity date of March 7, 2022. At December 31, 2021, Montana-Dakota had no amount outstanding under the agreement. The agreement contains customary covenants and provisions, including a covenant of Montana-Dakota not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. The covenants also include certain restrictions on the sale of certain assets, loans and investments.

Long-term debt

Long-term Debt Outstanding Long-term debt outstanding was as follows:


	Weighted Average Interest Rate at December 31, 2021		2021		2020
			(In thousands)
Senior Notes due on dates ranging from October 22, 2022 to September 15, 2061	4.32	%	$	2,125,000	$	1,950,000
Commercial paper supported by revolving credit agreements	.40	%	450,300		125,600
Credit agreements due on June 7, 2024	1.94	%	127,500		95,900
Medium-Term Notes due on dates ranging from September 15, 2027 to March 16, 2029	7.32	%	35,000		35,000
Term Loan Agreement due on September 3, 2032	2.00	%	7,700		8,400
Other notes due on dates ranging from January 2, 2022 to January 1, 2061	1.03	%	2,564		4,034
Less unamortized debt issuance costs			6,090		5,803
Less discount			74		1
Total long-term debt			2,741,900		2,213,130
Less current maturities			148,053		1,555
Net long-term debt			$	2,593,847	$	2,211,575

Montana-Dakota 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.

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Montana-Dakota's ratio of total debt to total capitalization at December 31, 2021, was 51 percent.

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.

Cascade's ratio of total debt to total capitalization at December 31, 2021, was 51 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.

Intermountain's ratio of total debt to total capitalization at December 31, 2021, was 50 percent.

Centennial Centennial'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. Centennial's revolving credit agreement contains customary covenants and provisions, including a covenant of Centennial not to permit, as of the end of any fiscal quarter, the ratio of total consolidated debt to total consolidated capitalization to be greater than 65 percent. Other covenants include restricted payments, restrictions on the sale of certain assets, limitations on subsidiary indebtedness, minimum consolidated net worth, limitations on priority debt and the making of certain loans and investments.

Centennial's ratio of total debt to total capitalization, as defined by its debt covenants, at December 31, 2021, was 43 percent.

Certain of Centennial's financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default.

WBI Energy Transmission WBI Energy Transmission has a $300.0 million uncommitted note purchase and private shelf agreement with an expiration date of May 16, 2022. WBI Energy Transmission had $195.0 million of notes outstanding at December 31, 2021, which reduced the remaining capacity under this uncommitted private shelf agreement to $105.0 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 and 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, 2021, was 38 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, 2021, were as follows:


	2022		2023		2024		2025		2026		Thereafter
	(In thousands)
Long-term debt maturities	$	148,053	$	77,925	$	638,604	$	177,802	$	140,802	$	1,564,878

90 MDU Resources Group, Inc. Form 10-K

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Note 10 - 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 segments. 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, operating lease liabilities due within one year and, if applicable, 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:


	2021		2020
	(In thousands)
Lease costs:
Short-term lease cost	$	132,449	$	135,376
Operating lease cost	46,622		45,319
Variable lease cost	1,516		1,319
	$	180,587	$	182,014


	2021			2020
	(Dollars in thousands)
Weighted average remaining lease term	2.67 years			2.73 years
Weighted average discount rate	3.54		%	4.03		%
Cash paid for amounts included in the measurement of lease liabilities	$	43,489		$	45,043

The reconciliation of future undiscounted cash flows to operating lease liabilities presented on the Consolidated Balance Sheet at December 31, 2021, was as follows:


	(In thousands)
2022	$	38,605
2023	27,460
2024	19,732
2025	12,278
2026	6,681
Thereafter	44,039
Total	148,795
Less discount	24,174
Total operating lease liabilities	$	124,621

Lessor accounting

The Company leases certain equipment to third parties through its utility and construction services segments, which are considered short-term operating leases with terms of less than 12 months. The Company recognized revenue from operating leases of $50.1 million and $48.0 million for the years ended December 31, 2021 and 2020, respectively. At December 31, 2021, the Company had $9.2 million of lease receivables with a majority due within 12 months or less.

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Note 11 - Asset Retirement Obligations

The Company records obligations related to retirement costs of natural gas distribution mains and lines, natural gas transmission lines, natural gas storage wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, 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:


	2021		2020
	(In thousands)
Balance at beginning of year	$	446,919	$	417,575
Liabilities incurred	12,454		11,560
Liabilities acquired	1,805		1,378
Liabilities settled	(15,155)		(5,369)
Accretion expense*	21,214		21,668
Revisions in estimates	1,449		107
Balance at end of year	$	468,686	$	446,919

*Includes $19.6 million and $20.1 million in 2021 and 2020, respectively, recorded to regulatory assets.

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 12 - Equity

The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly dividends for 84 consecutive years with an increase in the dividend amount for the last 31 consecutive years. For the years ended December 31, 2021, 2020 and 2019, dividends declared on common stock were $.8550, $.8350 and $.8150 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, 2021, 2020 and 2019, the dividends declared to common stockholders were $173.0 million, $167.4 million and $162.1 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.

Pursuant to a covenant under its revolving credit agreement, Centennial may only declare or pay distributions if, as of the last day of any fiscal quarter, the ratio of Centennial's average consolidated indebtedness as of the last day of such fiscal quarter and each of the preceding three fiscal quarters to Centennial's Consolidated trailing 12 month EBITDA does not exceed 3.5 to 1. In addition, 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 $1.7 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, 2021.

92 MDU Resources Group, Inc. Form 10-K

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Details of the Company's "at-the-market" offering activity for the years ended December 31 was as follows:


	2021		2020
	(In millions)
Shares issued	2.8		—
Net proceeds *	$	88.8	$	—
Issuance costs	$	1.2	$	—

* Net proceeds were used for capital expenditures.

The K-Plan provides participants the option to invest in the Company's common stock. For the years ended December 31, 2021, 2020 and 2019, the K-Plan purchased shares of common stock on the open market or issued original issue common stock of the Company. At December 31, 2021, 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, 2021 and 2020, there were no shares outstanding.

Note 13 - Stock-Based Compensation

The Company has stock-based compensation plans under which it is currently authorized to grant restricted stock and other stock awards. As of December 31, 2021, there were 3.7 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.

Total stock-based compensation expense (after tax) was $12.0 million, $10.8 million and $6.5 million in 2021, 2020 and 2019, respectively.

As of December 31, 2021, total remaining unrecognized compensation expense related to stock-based compensation was approximately $10.9 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 41,925 shares with a fair value of $1.2 million, 45,273 shares with a fair value of $1.1 million and 41,644 shares with a fair value of $1.2 million issued to non-employee directors during the years ended December 31, 2021, 2020 and 2019, respectively.

Restricted stock awards

In February 2021, key employees were granted restricted stock awards under the long-term performance-based incentive plan. The shares vest over three years, contingent on continued employment. Compensation expense is recognized over the vesting period. At December 31, 2021, the number of outstanding shares granted was 93,700 with a weighted average grant-date fair value of $27.35 per share.

Performance share awards

Since 2003, key employees of the Company have been granted performance share awards each year under the long-term performance-based incentive plan. Entitlement to performance shares is established by either the market condition or the performance metrics and service condition relative to the designated award.

Target grants of performance shares outstanding at December 31, 2021, were as follows:


Grant Date	Performance Period	Target Grant of Shares
February 2020	2020-2022	273,918
February 2021	2021-2023	281,129

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Under the market condition for these performance share awards, participants may earn from zero to 200 percent of the apportioned target grant of shares based on the Company's total shareholder return relative to that of the selected peer group. Compensation expense is based on the grant-date fair value as determined by Monte Carlo simulation. The blended volatility term structure ranges are 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 grants applicable to the market condition for certain performance shares issued in 2021, 2020 and 2019 were:


	2021	2020	2019
Weighted average grant-date fair value	$37.96	$40.75	$35.07
Blended volatility range	35.37% - 46.35%	15.30% - 15.97%	19.50% - 19.69%
Risk-free interest rate range	.02% - .20%	1.45% - 1.62%	2.46% - 2.55%
Weighted average discounted dividends per share	$3.16	$2.91	$2.85

Under the performance conditions for these performance share awards, participants may earn from zero to 200 percent of the apportioned target grant of shares. The performance conditions are based on the Company's compound annual growth rate in earnings from continuing operations before interest, taxes, depreciation, depletion and amortization and 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 2021, 2020 and 2019 was $27.35, $31.63 and $26.25, respectively.

The fair value of the performance shares that vested during the years ended December 31, 2021, 2020 and 2019, was $13.7 million, $9.7 million and $9.7 million, respectively.

A summary of the status of the performance share awards for the year ended December 31, 2021, was as follows:


	Number of Shares	Weighted Average Grant-Date Fair Value
Nonvested at beginning of period	613,174	$	33.24
Granted	284,104	32.66
Additional performance shares earned	116,467	22.68
Less:
Vested	443,661	28.57
Forfeited	15,037	35.49
Nonvested at end of period	555,047	$	34.40

Note 14 - 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, 2019	$	(1,430)	$	(40,734)	$	62	$	(42,102)
Other comprehensive loss before reclassifications	—		(8,395)		(1)		(8,396)
Amounts reclassified from accumulated other comprehensive loss	446		1,922		52		2,420
Net current-period other comprehensive income (loss)	446		(6,473)		51		(5,976)
At December 31, 2020	(984)		(47,207)		113		(48,078)
Other comprehensive income (loss) before reclassifications	—		4,876		(252)		4,624
Amounts reclassified from accumulated other comprehensive loss	446		1,870		134		2,450
Net current-period other comprehensive income (loss)	446		6,746		(118)		7,074
At December 31, 2021	$	(538)	$	(40,461)	$	(5)	$	(41,004)

94 MDU Resources Group, Inc. Form 10-K

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The following amounts were reclassified out of accumulated other comprehensive loss into net income. The amounts presented in parenthesis indicate a decrease to net income on the Consolidated Statements of Income. The reclassifications for the years ended December 31 were as follows:


	2021		2020		Location on Consolidated Statements of Income
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income	$	(591)	$	(591)	Interest expense
	145		145		Income taxes
	(446)		(446)
Amortization of postretirement liability losses included in net periodic benefit cost	(2,485)		(2,552)		Other income
	615		630		Income taxes
	(1,870)		(1,922)
Reclassification adjustment for loss on available-for-sale investments included in net income	(170)		(66)		Other income
	36		14		Income taxes
	(134)		(52)
Total reclassifications	$	(2,450)	$	(2,420)

Note 15 - Income Taxes

The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows:


	2021		2020		2019
	(In thousands)
United States	$	466,651	$	474,856	$	398,532
Foreign	—		261		(87)
Income before income taxes from continuing operations	$	466,651	$	475,117	$	398,445

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:


	2021		2020		2019
	(In thousands)
Current:
Federal	$	17,121	$	65,006	$	(3,502)
State	11,549		21,234		3,366
Foreign	—		151		—
	28,670		86,391		(136)
Deferred:
Income taxes:
Federal	45,885		(3,735)		50,218
State	12,610		(625)		12,098
Investment tax credit - net	1,755		2,559		1,099
	60,250		(1,801)		63,415
Total income tax expense	$	88,920	$	84,590	$	63,279

MDU Resources Group, Inc. Form 10-K 95

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Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:


	2021		2020
	(In thousands)
Deferred tax assets:
Postretirement	$	45,752	$	51,495
Compensation-related	37,917		40,477
Operating lease liabilities	26,710		25,963
Asset retirement obligations	8,696		8,060
Legal and environmental contingencies	8,603		9,467
Customer advances	7,683		7,463
Payroll tax deferral	6,940		14,010
Other	39,960		37,944
Total deferred tax assets	182,261		194,879
Deferred tax liabilities:
Basis differences on property, plant and equipment	585,095		536,966
Postretirement	48,302		49,233
Operating lease right-of-use-assets	26,570		25,858
Intangible assets	21,074		19,514
Other	81,070		67,922
Total deferred tax liabilities	762,111		699,493
Valuation allowance	12,112		11,484
Net deferred income tax liability	$	591,962	$	516,098

As of December 31, 2021 and 2020, the Company had various state income tax net operating loss carryforwards of $164.8 million and $151.5 million, respectively, and federal and state income tax credit carryforwards, excluding alternative minimum tax credit carryforwards, of $35.6 million and $37.1 million, respectively. The state credits include various regulatory investment tax credits of approximately $35.0 million and $36.3 million at December 31, 2021 and 2020, respectively. The state income tax credit carryforwards are due to expire between 2024 and 2035. Changes in tax regulations or assumptions regarding current and future taxable income could require additional valuation allowances in the future.

The following table reconciles the change in the net deferred income tax liability from December 31, 2020, to December 31, 2021, to deferred income tax expense:


	2021
(In thousands)
Change in net deferred income tax liability from the preceding table	$	75,864
Deferred taxes associated with other comprehensive loss	(2,355)
Excess deferred income tax amortization	(10,295)
Other	(2,964)
Deferred income tax expense for the period	$	60,250

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,	2021			2020			2019
	Amount		%	Amount		%	Amount		%
	(Dollars in thousands)
Computed tax at federal statutory rate	$	97,997	21.0	$	99,775	21.0	$	83,674	21.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax	19,496		4.2	17,845		3.8	14,029		3.5
Federal renewable energy credit	(13,914)		(3.0)	(16,009)		(3.4)	(15,843)		(4.0)
Tax compliance and uncertain tax positions	(477)		(.1)	(3,543)		(.7)	(2,739)		(.7)
Excess deferred income tax amortization	(10,295)		(2.2)	(12,517)		(2.6)	(11,904)		(3.0)
Other	(3,887)		(.8)	(961)		(.3)	(3,938)		(.9)
Total income tax expense	$	88,920	19.1	$	84,590	17.8	$	63,279	15.9

96 MDU Resources Group, Inc. Form 10-K

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The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions. The Company is no longer subject to U.S. federal or non-U.S. income tax examinations by tax authorities for years ending prior to 2018. With few exceptions, as of December 31, 2021, the Company is no longer subject to state and local income tax examinations by tax authorities for years ending prior to 2018.

For the years ended December 31, 2021, 2020 and 2019, 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 16 - Cash Flow Information

Cash expenditures for interest and income taxes for the years ended December 31 were as follows:


	2021		2020		2019
	(In thousands)
Interest, net*	$	91,165	$	88,681	$	93,414
Income taxes paid (refunded), net**	$	71,079	$	65,536	$	(8,475)

* AFUDC - borrowed was $2.8 million, $2.6 million and $2.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.

**Income taxes paid (refunded), including discontinued operations, were $70.9 million, $59.4 million and $(9.4) million for the years ended December 31, 2021, 2020 and 2019, respectively.

Noncash investing and financing transactions at December 31 were as follows:


	2021		2020		2019
	(In thousands)
Property, plant and equipment additions in accounts payable	$	57,605	$	26,082	$	46,119
Right-of-use assets obtained in exchange for new operating lease liabilities	$	55,987	$	54,356	$	54,880
Debt assumed in connection with a business combination	$	10	$	—	$	1,163
Accrual for holdback payment related to a business combination	$	—	$	2,500	$	—

Note 17 - 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 and other energy-related services.

The construction materials and contracting segment mines, processes and sells construction aggregates (crushed stone, sand and gravel); produces and sells asphalt mix; and supplies ready-mix concrete. This segment focuses on vertical integration of its contracting services with its construction materials to support the aggregate-based product lines including aggregate placement, asphalt and concrete paving, and site development and grading. Although not common to all locations, other products include the sale of cement, asphalt oil for various commercial and roadway applications, various finished concrete products and other building materials and related contracting services. This segment operates in the central, southern and western United States, including Alaska and Hawaii.

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 country. These specialty contracting services are provided to utilities and 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 distribution of transmission 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

MDU Resources Group, Inc. Form 10-K 97

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with corporate functions and certain general and administrative costs (reflected in operation and maintenance expense) and interest expense, which were previously allocated to the refining business and Fidelity and do not meet the criteria for income (loss) from discontinued operations.

Discontinued operations include 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:


	2021		2020		2019
			(In thousands)
External operating revenues:
Regulated operations:
Electric	$	349,039	$	331,538	$	351,725
Natural gas distribution	971,364		847,651		865,222
Pipeline	69,940		69,957		62,357
	1,390,343		1,249,146		1,279,304
Non-regulated operations:
Pipeline	12,918		15,389		21,835
Construction materials and contracting	2,228,306		2,177,585		2,189,651
Construction services	2,049,082		2,090,685		1,845,896
Other	84		(55)		90
	4,290,390		4,283,604		4,057,472
Total external operating revenues	$	5,680,733	$	5,532,750	$	5,336,776
Intersegment operating revenues:
Regulated operations:
Electric	$	543	$	491	$	—
Natural gas distribution	576		534		—
Pipeline	58,989		57,977		56,037
	60,108		59,002		56,037
Non-regulated operations:
Pipeline	689		554		215
Construction materials and contracting	624		417		1,066
Construction services	2,555		5,038		3,370
Other	13,630		11,958		16,461
	17,498		17,967		21,112
Intersegment eliminations	(77,606)		(76,969)		(77,149)
Total intersegment operating revenues	$	—	$	—	$	—
Depreciation, depletion and amortization:
Electric	$	66,750	$	62,998	$	58,721
Natural gas distribution	86,065		84,580		79,564
Pipeline	20,569		21,669		21,220
Construction materials and contracting	100,974		89,626		77,450
Construction services	20,270		23,523		17,038
Other	4,586		2,704		2,024
Total depreciation, depletion and amortization	$	299,214	$	285,100	$	256,017
Operating income (loss):
Electric	$	66,335	$	63,434	$	64,039
Natural gas distribution	89,173		73,082		69,188
Pipeline	48,078		49,436		42,796
Construction materials and contracting	191,077		214,498		179,955
Construction services	145,754		147,644		126,426
Other	(6,198)		(3,169)		(1,184)
Total operating income	$	534,219	$	544,925	$	481,220

98 MDU Resources Group, Inc. Form 10-K

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	2021		2020		2019
			(In thousands)
Interest expense:
Electric	$	26,712	$	26,699	$	25,334
Natural gas distribution	37,265		36,798		35,488
Pipeline	7,010		7,622		7,198
Construction materials and contracting	19,218		20,577		23,792
Construction services	3,540		4,095		5,331
Other	342		883		1,859
Intersegment eliminations	(103)		(155)		(415)
Total interest expense	$	93,984	$	96,519	$	98,587
Income tax expense (benefit):
Electric	$	(7,626)	$	(11,636)	$	(12,650)
Natural gas distribution	8,366		5,746		1,405
Pipeline	9,594		7,650		7,219
Construction materials and contracting	43,459		47,431		37,389
Construction services	35,426		35,797		29,973
Other	(299)		(398)		(57)
Total income tax expense	$	88,920	$	84,590	$	63,279

Net income (loss):
Regulated operations:
Electric	$	51,906	$	55,601	$	54,763
Natural gas distribution	51,596		44,049		39,517
Pipeline	39,583		35,453		28,255
	143,085		135,103		122,535
Non-regulated operations:
Pipeline	1,313		1,559		1,348
Construction materials and contracting	129,755		147,325		120,371
Construction services	109,402		109,721		92,998
Other	(5,824)		(3,181)		(2,086)
	234,646		255,424		212,631
Income from continuing operations	377,731		390,527		335,166
Income (loss) from discontinued operations, net of tax	400		(322)		287
Net income	$	378,131	$	390,205	$	335,453
Capital expenditures:
Electric	$	82,427	$	114,676	$	99,449
Natural gas distribution	170,411		193,048		206,799
Pipeline	234,803		62,224		71,477
Construction materials and contracting	417,524		191,635		190,092
Construction services	29,140		83,651		60,500
Other	1,501		3,045		8,181
Total capital expenditures (a)	$	935,806	$	648,279	$	636,498

MDU Resources Group, Inc. Form 10-K 99

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	2021		2020		2019
			(In thousands)
Assets:
Electric (b)	$	1,810,695	$	2,123,693	$	1,680,194
Natural gas distribution (b)	2,929,519		2,302,770		2,574,965
Pipeline	913,945		703,377		677,482
Construction materials and contracting	2,161,653		1,798,493		1,684,161
Construction services	845,262		818,662		761,127
Other (c)	248,489		305,157		303,279
Assets held for sale	872		1,220		1,851
Total assets	$	8,910,435	$	8,053,372	$	7,683,059
Property, plant and equipment:
Electric (b)	$	2,295,646	$	2,323,403	$	2,227,145
Natural gas distribution (b)	3,015,164		2,868,853		2,688,123
Pipeline	1,051,868		821,697		834,215
Construction materials and contracting	2,347,696		2,028,476		1,910,562
Construction services	225,758		220,796		213,370
Other	36,717		37,545		35,213
Less accumulated depreciation, depletion and amortization	3,216,461		3,133,831		2,991,486
Net property, plant and equipment	$	5,756,388	$	5,166,939	$	4,917,142

(a)Capital expenditures for 2021, 2020 and 2019 include noncash transactions such as capital expenditure-related accounts payable, AFUDC and accrual of holdback payments in connection with acquisitions totaling $38.7 million, $(15.7) million and $4.8 million, respectively.

(b)Includes allocations of common utility property.

(c)Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current and deferred assets).

Note 18 - 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 an exchange.

100 MDU Resources Group, Inc. Form 10-K

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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
	2021		2020		2021		2020
Change in benefit obligation:	(In thousands)
Benefit obligation at beginning of year	$	437,360	$	421,166	$	86,155	$	83,614
Service cost	—		—		1,600		1,532
Interest cost	9,819		12,093		1,862		2,437
Plan participants' contributions	—		—		641		752
Actuarial (gain) loss	(12,140)		27,737		(12,802)		2,203
Benefits paid	(23,542)		(23,636)		(3,996)		(4,383)
Benefit obligation at end of year	411,497		437,360		73,460		86,155
Change in net plan assets:
Fair value of plan assets at beginning of year	383,834		365,264		101,639		94,587
Actual return on plan assets	12,817		42,206		1,398		10,249
Employer contribution	—		—		476		434
Plan participants' contributions	—		—		641		752
Benefits paid	(23,542)		(23,636)		(3,996)		(4,383)
Fair value of net plan assets at end of year	373,109		383,834		100,158		101,639
Funded status - over (under)	$	(38,388)	$	(53,526)	$	26,698	$	15,484
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent assets - other	$	—	$	—	$	45,863	$	36,769
Other accrued liabilities	—		—		544		622
Noncurrent liabilities - other	38,388		53,526		18,621		20,663
Benefit obligation assets (liabilities) - net amount recognized	$	(38,388)	$	(53,526)	$	26,698	$	15,484
Amounts recognized in accumulated other comprehensive loss:
Actuarial loss	$	25,976	$	27,527	$	2,367	$	5,557
Prior service credit	—		—		(290)		(634)
Total	$	25,976	$	27,527	$	2,077	$	4,923
Amounts recognized in regulatory assets or liabilities:
Actuarial (gain) loss	$	142,166	$	154,013	$	(14,727)	$	(8,228)
Prior service credit	—		—		(5,193)		(6,808)
Total	$	142,166	$	154,013	$	(19,920)	$	(15,036)

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 2021, the actuarial gain recognized in the benefit obligation was primarily the result of an increase in the discount rate. In 2020, the actuarial loss recognized in the benefit obligation was primarily the result of a decrease in the discount rate. For more information on the discount rates, see the table below. Unrecognized pension actuarial 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:


	2021		2020
	(In thousands)
Projected benefit obligation	$	411,497	$	437,360
Accumulated benefit obligation	$	411,497	$	437,360
Fair value of plan assets	$	373,109	$	383,834

MDU Resources Group, Inc. Form 10-K 101

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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
	2021		2020		2019		2021		2020		2019
Components of net periodic benefit cost (credit):	(In thousands)
Service cost	$	—	$	—	$	—	$	1,600	$	1,532	$	1,142
Interest cost	9,819		12,093		15,225		1,862		2,437		2,986
Expected return on assets	(19,576)		(19,949)		(18,236)		(5,098)		(5,019)		(4,804)
Amortization of prior service credit	—		—		—		(1,398)		(1,398)		(1,398)
Recognized net actuarial loss	8,017		7,172		5,548		24		287		353


Net periodic benefit cost (credit), including amount capitalized	(1,740)		(684)		2,537		(3,010)		(2,161)		(1,721)
Less amount capitalized	—		—		—		150		156		113
Net periodic benefit cost (credit)	(1,740)		(684)		2,537		(3,160)		(2,317)		(1,834)
Other changes in plan assets and benefit obligations recognized in accumulated comprehensive loss:
Net (gain) loss	(265)		934		(144)		(2,811)		(259)		(127)

Amortization of actuarial loss	(1,286)		(1,155)		(904)		(135)		(306)		(110)
Amortization of prior service credit	—		—		—		100		101		100

Total recognized in accumulated other comprehensive loss	(1,551)		(221)		(1,048)		(2,846)		(464)		(137)
Other changes in plan assets and benefit obligations recognized in regulatory assets or liabilities:
Net (gain) loss	(5,116)		4,546		189		(6,292)		(3,793)		(8,168)

Amortization of actuarial gain (loss)	(6,731)		(6,017)		(4,644)		110		19		(242)
Amortization of prior service credit	—		—		—		1,298		1,297		1,297

Total recognized in regulatory assets or liabilities	(11,847)		(1,471)		(4,455)		(4,884)		(2,477)		(7,113)
Total recognized in net periodic benefit cost (credit), accumulated other comprehensive loss and regulatory assets or liabilities	$	(15,138)	$	(2,376)	$	(2,966)	$	(10,890)	$	(5,258)	$	(9,084)

Weighted average assumptions used to determine benefit obligations at December 31 were as follows:


	Pension Benefits				Other Postretirement Benefits
	2021		2020		2021		2020
Discount rate	2.64	%	2.30	%	2.66	%	2.30	%
Expected return on plan assets	6.00	%	6.00	%	5.50	%	5.50	%
Rate of compensation increase	N/A		N/A		3.00	%	3.00	%

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
	2021		2020		2021		2020
Discount rate	2.30	%	2.96	%	2.30	%	3.00	%
Expected return on plan assets	6.00	%	6.25	%	5.50	%	5.75	%
Rate of compensation increase	N/A		N/A		3.00	%	3.00	%

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, 2021, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 35 percent to 45 percent equity securities and 55 percent to 65 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 equity securities and 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.

102 MDU Resources Group, Inc. Form 10-K

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Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:


	2021		2020
Health care trend rate assumed for next year	7.0	%	7.0	%
Health care cost trend rate - ultimate	4.5	%	4.5	%
Year in which ultimate trend rate achieved	2031		2031

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 does not expect to contribute to its defined benefit pension plans in 2022 due to an additional $20.0 million contributed to the plans in 2019 creating prefunding credits to be used in future years. The Company expects to contribute approximately $601,000 to its postretirement benefit plans in 2022.

The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies at December 31, 2021, are as follows:


Years	Pension Benefits		Other Postretirement Benefits		Expected Medicare Part D Subsidy
			(In thousands)
2022	$	24,644	$	4,393	$	70
2023	24,766		4,522		65
2024	24,897		4,572		58
2025	24,739		4,612		52
2026	24,571		4,642		46
2027-2031	117,413		17,867		157

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.

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.

MDU Resources Group, Inc. Form 10-K 103

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The fair value of the Company's pension plans' assets (excluding cash) by class were as follows:


	Fair Value Measurements at December 31, 2021, 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, 2021
	(In thousands)
Assets:
Cash equivalents	$	—	$	4,637	$	—	$	4,637
Equity securities:
U.S. companies	7,483		—		—		7,483
International companies	—		1,279		—		1,279
Collective and mutual funds (a)	167,093		41,383		—		208,476
Corporate bonds	—		125,167		—		125,167
Municipal bonds	—		7,507		—		7,507
U.S. Government securities	7,113		1,902		—		9,015
Pooled separate accounts (b)	—		3,088		—		3,088
Investments measured at net asset value (c)	—		—		—		6,457
Total assets measured at fair value	$	181,689	$	184,963	$	—	$	373,109

(a)Collective and mutual funds invest approximately 37 percent in corporate bonds, 19 percent in common stock of international companies, 16 percent in common stock of large-cap U.S. companies, 9 percent in U.S. Government securities and 19 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, 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 statement of financial condition.


	Fair Value Measurements at December 31, 2020, 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, 2020
	(In thousands)
Assets:
Cash equivalents	$	—	$	7,841	$	—	$	7,841
Equity securities:
U.S. companies	12,844		—		—		12,844
International companies	—		1,727		—		1,727
Collective and mutual funds (a)	177,397		55,788		—		233,185
Corporate bonds	—		92,809		—		92,809
Municipal bonds	—		10,126		—		10,126
U.S. Government securities	11,177		2,695		—		13,872
Investments measured at net asset value (b)	—		—		—		11,430
Total assets measured at fair value	$	201,418	$	170,986	$	—	$	383,834

(a)Collective and mutual funds invest approximately 36 percent in corporate bonds, 24 percent in common stock of international companies, 18 percent in common stock of large-cap U.S. companies, 8 percent in cash equivalents, 5 percent in U.S. Government securities and 9 percent in other investments.

(b)In accordance with ASC 820 - Fair Value, 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 statement of financial condition.

The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.

104 MDU Resources Group, Inc. Form 10-K

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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.

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, 2021, 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, 2021
	(In thousands)
Assets:
Cash equivalents	$	—	$	4,281	$	—	$	4,281
Equity securities:
U.S. companies	2,332		—		—		2,332
International companies	—		1		—		1
Collective and mutual funds (a)	4		90		—		94
Insurance contract (b)	—		93,447		—		93,447
Investments measured at net asset value (c)	—		—		—		3
Total assets measured at fair value	$	2,336	$	97,819	$	—	$	100,158

(b)The insurance contract invests approximately 58 percent in corporate bonds, 13 percent in U.S. Government securities, 13 percent in common stock of large-cap U.S. companies, 5 percent in common stock of small-cap U.S. companies and 11 percent in other investments.


	Fair Value Measurements at December 31, 2020, 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, 2020
	(In thousands)
Assets:
Cash equivalents	$	—	$	3,517	$	—	$	3,517
Equity securities:
U.S. companies	1,850		—		—		1,850
International companies	—		2		—		2
Collective and mutual funds (a)	10		147		—		157
Insurance contract (b)	—		96,103		—		96,103
Investments measured at net asset value (c)	—		—		—		10
Total assets measured at fair value	$	1,860	$	99,769	$	—	$	101,639

(b)The insurance contract invests approximately 67 percent in corporate bonds, 10 percent in common stock of large-cap U.S. companies, 12 percent in U.S. Government securities, 4 percent in common stock of small-cap U.S. companies, 1 percent in cash equivalents and 6 percent in other investments.

MDU Resources Group, Inc. Form 10-K 105

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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:


	2021		2020
	(In thousands)
Projected benefit obligation	$	92,918	$	101,242
Accumulated benefit obligation	$	92,918	$	101,242

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:


	2021		2020		2019
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	—	$	58	$	109
Interest cost	1,912		2,606		3,473
Recognized net actuarial loss	1,164		1,192		764
Net periodic benefit cost	$	3,076	$	3,856	$	4,346

Weighted average assumptions used at December 31 were as follows:


	2021		2020
Benefit obligation discount rate	2.39	%	1.97	%
Benefit obligation rate of compensation increase	N/A		N/A
Net periodic benefit cost discount rate	1.97	%	2.73	%
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, 2021, are expected to aggregate as follows:


	2022		2023		2024		2025		2026		2027-2031
	(In thousands)
Nonqualified benefits	$	6,877	$	6,890	$	7,354	$	7,537	$	7,609	$	31,983

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 2021, 2020 and 2019 were $2.4 million, $1.8 million and $1.6 million, respectively.

The amount of investments that the Company anticipates using to satisfy obligations under these plans at December 31 was as follows:


	2021		2020
	(In thousands)
Investments
Insurance contract*	$	109,603	$	100,104
Life insurance**	38,356		39,779
Other	10,190		8,917
Total investments	$	158,149	$	148,800

*For more information on the insurance contract, see Note 8.

**Investments of life insurance are carried on plan participants (payable upon the employee's death).

106 MDU Resources Group, Inc. Form 10-K

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Defined contribution plans

The Company sponsors various defined contribution plans for eligible employees and the costs incurred under these plans were $45.4 million in 2021, $50.1 million in 2020 and $51.8 million in 2019.

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 2021 and 2020 is for the plan's year-end at December 31, 2020, and December 31, 2019, 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.


	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		2021	2020		2021		2020		2019
					(In thousands)
Edison Pension Plan	936061681-001	Green	Green	No	$	18,331	$	16,121	$	12,252	No	12/31/2023
IBEW Local 212 Pension Trust	316127280-001	Green as of 4/30/2021	Green as of 4/30/2020	No	1,733		1,521		1,110		No	6/1/2025
IBEW Local 357 Pension Plan A	886023284-001	Green	Green	No	6,485		9,913		10,162		No	5/31/2024
IBEW Local 82 Pension Plan	316127268-001	Green as of 6/30/2021	Green as of 6/30/2020	No	1,353		1,373		1,662		No	12/3/2023
Idaho Plumbers and Pipefitters Pension Plan	826010346-001	Green as of 5/31/2021	Green as of 5/31/2020	No	1,528		1,370		1,307		No	3/31/2023
National Electrical Benefit Fund	530181657-001	Green	Green	No	14,361		14,484		12,679		No	5/31/2021- 5/31/2026	*
Pension and Retirement Plan of Plumbers and Pipefitters Local 525	886003864-001	Green	Green	No	4,345		6,266		4,747		No	9/30/2024
Pension Trust Fund for Operating Engineers	946090764-001	Yellow	Yellow	Implemented	2,495		2,680		2,598		No	6/15/2022- 6/30/2023
Sheet Metal Workers Pension Plan of Southern CA, AZ, and NV	956052257-001	Yellow	Yellow	Implemented	2,615		3,255		2,119		No	6/30/2024
Southern California IBEW-NECA Pension Trust Fund	956392774-001	Yellow as of 6/30/2021	Yellow as of 6/30/2020	Implemented	2,746		1,714		1,477		No	6/30/2022- 5/31/2026
Western Conference of Teamsters Pension Plan	916145047-001	Green	Green	No	3,006		3,025		2,814		No	12/31/2023- 12/31/2025
Other funds					23,390		23,722		19,598
Total contributions					$	82,388	$	85,444	$	72,525

*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.

MDU Resources Group, Inc. Form 10-K 107

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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			2020 and 2019
IBEW Local 82 Pension Plan			2020 and 2019
IBEW Local 124 Pension Trust Fund			2020 and 2019
IBEW Local 212 Pension Trust Fund			2020 and 2019
IBEW Local 357 Pension Plan A			2020 and 2019
IBEW Local 648 Pension Plan			2020 and 2019
IBEW Local 683 Pension Fund Pension Plan			2020 and 2019
IBEW Local Union No 226 Open End Pension Fund			2020 and 2019
Idaho Plumbers and Pipefitters Pension Plan			2020 and 2019
International Union of Operating Engineers Local 701 Pension Trust Fund			2020 and 2019
Minnesota Teamsters Construction Division Pension Fund			2020 and 2019
Pension and Retirement Plan of Plumbers and Pipefitters Local 525			2020 and 2019
Southwest Marine Pension Trust			2020 and 2019

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 $66.1 million, $63.8 million and $59.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Amounts contributed in 2021, 2020 and 2019 to defined contribution multiemployer plans were $54.8 million, $54.2 million and $49.2 million, respectively.

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Note 19 - 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 one major transmission line (BSSE). 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		2021		2020
			(In thousands)
Big Stone Station:	22.7	%
Utility plant in service			$	157,259	$	155,967
Construction work in progress			571		104
Less accumulated depreciation			47,293		45,435
			$	110,537	$	110,636
BSSE:	50.0	%
Utility plant in service			$	107,424	$	107,442
Construction work in progress			—		—
Less accumulated depreciation			4,506		2,682
			$	102,918	$	104,760
Coyote Station:	25.0	%
Utility plant in service			$	157,764	$	159,784
Construction work in progress			784		323
Less accumulated depreciation			109,202		108,852
			$	49,346	$	51,255
Wygen III:	25.0	%
Utility plant in service			$	66,357	$	66,101
Construction work in progress			108		232
Less accumulated depreciation			11,383		10,038
			$	55,082	$	56,295

Note 20 - 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.

MNPUC

Great Plains defers the difference between the actual cost of gas spent to serve customers and that recovered from customers on a monthly basis. Annually, Great Plains prepares a true-up pursuant to the purchased gas adjustment tariff. On August 30, 2021, the MNPUC issued an order to allow Great Plains recovery of an out-of-cycle cost of gas adjustment of $8.8 million over a period of 27 months. The order was effective September 1, 2021, and is subject to a prudence review by the MNPUC. The requested increase was for the February 2021 extreme cold weather, primarily in the central United States, and market conditions surrounding the natural gas commodity market. The MNPUC prudence review is pending with an order to be issued on or before August 29, 2022.

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 November 1, 2021, Montana-Dakota filed an annual update to its renewable resource cost adjustment requesting to recover a revised revenue requirement of approximately $12.4 million annually, not including the prior period true-up adjustment. The update reflects a decrease of approximately $2.0 million from the revenues currently included in rates. On January 26, 2022, the NDPSC approved the decrease with rates effective February 1, 2022.

MDU Resources Group, Inc. Form 10-K 109

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SDPUC

On March 11, 2021, Montana-Dakota filed an informational update to the infrastructure rider rate tariff with the SDPUC related to the retirement of Unit 1 at Lewis & Clark Station. The filing includes the annual revenue requirement offset by the related amortization of the accelerated depreciation on the plant, net of excess deferred income taxes, and the decommissioning costs projected to be incurred in 2021 resulting in no impact to customers. On November 15, 2021, the SDPUC approved the request.

WUTC

On September 30, 2021, Cascade filed an application with the WUTC for a natural gas rate increase of approximately $13.7 million annually or approximately 5.1 percent above current rates. The requested increase was primarily to recover investments made in infrastructure upgrades, as well as to recover 2021 wage increases. The WUTC has 11 months to render a final decision on the rate case. This matter is pending before the WUTC.

FERC

On September 1, 2021, Montana-Dakota filed an update to its transmission formula rate under the MISO tariff for its multi-value project for $13.4 million, which was effective January 1, 2022.

Note 21 - 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, 2021 and 2020, the Company accrued liabilities which have not been discounted, including liabilities held for sale, of $37.0 million and $41.5 million, respectively. At December 31, 2021 and 2020, the Company also recorded corresponding insurance receivables of $14.1 million and $17.5 million, respectively, and regulatory assets of $21.2 million and $21.3 million, respectively, related to the accrued liabilities. The accruals are for contingencies resulting from litigation, production taxes, royalty claims 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

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of the riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. along the Willamette River. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site where the EPA wants responsible parties to share in the costs of cleanup. The EPA entered into a consent order with certain other PRPs referred to as the Lower Willamette Group for a remedial investigation and feasibility study. The Lower Willamette Group has indicated that it has incurred over $115.0 million in investigation related costs. Knife River - Northwest has joined with approximately 100 other PRPs, including the Lower Willamette Group members, in a voluntary process to establish an allocation of costs for the site. Costs to be allocated would include costs incurred by the Lower Willamette Group as well as costs to implement and fund remediation of the site.

In January 2017, the EPA issued a Record of Decision adopting a selected remedy which is expected to take 13 years to complete with a then estimated present value of approximately $1 billion. Corrective action will not be taken until remedial design/remedial action plans are approved by the EPA. In 2020, the EPA encouraged certain PRPs to enter into consent agreements to perform remedial design covering the entire site and proposed dividing the site into multiple subareas for remedial design. Certain PRPs executed consent agreements for remedial design work and certain others were issued unilateral administrative orders to perform design work. Knife River - Northwest is not subject to either a voluntary agreement or unilateral order to perform remedial design work. In February 2021, the EPA announced that 100 percent of the site's area requiring active cleanup is in the remedial design process. Site-wide remediation activities are not expected to commence for a number of years.

Knife River - Northwest was also notified that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the site. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

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At this time, Knife River - Northwest does not believe it is a responsible party and has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement.

The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced matter.

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 was started in 2020, which is estimated to cost approximately $823,000. The environmental assessment report is expected to be submitted to the MTDEQ in 2022. 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 $419,000 for the remediation and investigation costs, and has incurred costs of $505,000 as of December 31, 2021. 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. This matter is pending before the MTPSC.

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 $7.6 million of which $5.3 million has been incurred as of December 31, 2021. 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 $71.0 million. At December 31, 2021, Cascade has accrued $2.3 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.

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. Development of design documents is anticipated to be completed by the end of 2022 with the remedy construction expected to occur in 2023. 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.

MDU Resources Group, Inc. Form 10-K 111

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Part II

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; royalties; information technology; and construction materials. Certain of these contracts are subject to variability in volume and price. The commitment terms vary in length, up to 38 years. The commitments under these contracts as of December 31, 2021, were:


	2022		2023		2024		2025		2026		Thereafter
	(In thousands)
Purchase commitments	$	589,898	$	200,667	$	141,383	$	99,545	$	86,628	$	731,679

These commitments were not reflected in the Company's consolidated financial statements. Amounts purchased under various commitments for the years ended December 31, 2021, 2020 and 2019, were $849.3 million, $666.0 million and $686.5 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, 2021, the fixed maximum amounts guaranteed under these agreements aggregated $134.8 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 $28.6 million in 2022; $45.2 million in 2023; $50.2 million in 2024; $800,000 in 2025; $800,000 in 2026; $200,000 thereafter; and $9.0 million, which has no scheduled maturity date. There were no amounts outstanding under the previously mentioned guarantees at December 31, 2021. 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.

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, 2021, the fixed maximum amounts guaranteed under these letters of credit aggregated $25.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate to $25.2 million in 2022 and $500,000 in 2023. There were no amounts outstanding under the previously mentioned letters of credit at December 31, 2021. In the event of default under these letter of credit obligations, the subsidiary guaranteeing the letter of credit would be obligated for reimbursement of payments made under the letter of credit.

In addition, Centennial, Knife River 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, Knife River 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, 2021.

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, 2021, approximately $934.4 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

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, 2021, 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 $31.5 million.

112 MDU Resources Group, Inc. Form 10-K

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Part II

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-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota (50 percent ownership)
Btu			British thermal unit
Cascade			Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
Centennial			Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital			Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial's Consolidated EBITDA			Centennial's consolidated net income from continuing operations plus the related interest expense, taxes, depreciation, depletion, amortization of intangibles and any non-cash charge relating to asset impairment for the preceding 12-month period
Company			MDU Resources Group, Inc.
COVID-19			Coronavirus disease 2019
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, depletion 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
Knife River			Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest			Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
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
MMBtu			Million Btu
MNPUC			Minnesota Public Utilities Commission
Montana-Dakota			Montana-Dakota Utilities Co. a direct wholly owned subsidiary of MDU Energy Capital
MTDEQ			Montana Department of Environmental Quality
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
SEC			United States Securities and Exchange Commission

MDU Resources Group, Inc. Form 10-K 113

Index

Part II


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)

114 MDU Resources Group, Inc. Form 10-K

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Part II


Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.


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, 2021, 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.


Item 9B. Other Information

None.


Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

None.

MDU Resources Group, Inc. Form 10-K 115

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Part III


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.


Item 11. Executive Compensation

Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.


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, 2021, with respect to the Company's equity compensation plans:


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted average exercise price of outstanding options, warrants and rights			(c) 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)	648,747	(2)	$	—	(3)	3,032,901	(4)(5)
Equity compensation plans not approved by stockholders	N/A		N/A			N/A
Total	648,747		$	—		3,032,901

(1) Consists of the Non-Employee Director Long-Term Incentive Compensation Plan and the Long-Term Performance-Based Incentive Plan.

(2) Consists of restricted stock awards and performance share awards.

(3) No weighted average exercise price is shown for the restricted stock awards or performance share awards because such awards have no exercise price.

(4) This amount includes 2,849,487 shares available for future issuance under the Long-Term Performance-Based Incentive Plan in connection with grants of restricted stock, performance units, performance shares or other equity-based awards.

(5) This amount includes 183,414 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.


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.


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.

116 MDU Resources Group, Inc. Form 10-K

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Part IV


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, 2021			68

Consolidated Statements of Comprehensive Income for each of the three years in the period ended December 31, 2021			69

Consolidated Balance Sheets at December 31, 2021 and 2020			70

Consolidated Statements of Equity for each of the three years in the period ended December 31, 2021			71

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2021			72

Notes to Consolidated Financial Statements			73


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, 2021			118

Condensed Balance Sheets at December 31, 2021 and 2020			119

Condensed Statements of Cash Flows for each of the three years in the period ended December 31, 2021			120

Notes to Condensed Financial Statements			120

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			121

MDU Resources Group, Inc. Form 10-K 117

Index

Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Income and Comprehensive Income


Years ended December 31,	2021		2020		2019
	(In thousands)
Equity in earnings of subsidiaries from continuing operations	$	377,731	$	390,527	$	335,166
Income from continuing operations	377,731		390,527		335,166
Equity in earnings (loss) of subsidiaries from discontinued operations	400		(322)		287
Net income	$	378,131	$	390,205	$	335,453
Comprehensive income	$	385,205	$	384,229	$	331,693

The accompanying notes are an integral part of these condensed financial statements.

118 MDU Resources Group, Inc. Form 10-K

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Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Balance Sheets


December 31,	2021		2020
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	6,159	$	8,781
Receivables, net	6,120		4,865
Accounts receivable from subsidiaries	49,696		50,539
Prepayments and other current assets	2,528		1,612
Total current assets	64,503		65,797
Noncurrent assets
Investments	55,686		52,000
Investment in subsidiaries	3,368,537		3,069,956
Deferred income taxes	7,364		9,691
Operating lease right-of-use assets	114		56
Other	26,558		28,866
Total noncurrent assets	3,458,259		3,160,569
Total assets	$	3,522,762	$	3,226,366

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	2,546	$	2,135
Accounts payable to subsidiaries	6,133		5,412
Taxes payable	1,672		4,056
Dividends payable	44,229		42,611
Accrued compensation	4,098		7,825
Operating lease liabilities due within one year	52		40
Other accrued liabilities	7,309		6,881
Total current liabilities	66,039		68,960
Noncurrent liabilities:
Operating lease liabilities	62		16
Other	73,787		78,285
Total noncurrent liabilities	73,849		78,301
Commitments and contingencies
Stockholders' equity:
Common stock Authorized - 500,000,000 shares, $1.00 par value Shares issued - 203,889,661 at December 31, 2021 and 201,061,198 at December 31, 2020	203,889		201,061
Other paid-in capital	1,461,205		1,371,385
Retained earnings	1,762,410		1,558,363
Accumulated other comprehensive loss	(41,004)		(48,078)
Treasury stock at cost - 538,921 shares	(3,626)		(3,626)

Total stockholders' equity	3,382,874		3,079,105
Total liabilities and stockholders' equity	$	3,522,762	$	3,226,366

The accompanying notes are an integral part of these condensed financial statements.

MDU Resources Group, Inc. Form 10-K 119

Index

Part IV

MDU RESOURCES GROUP, INC.

Schedule I - Condensed Financial Information of Registrant (Unconsolidated)

Condensed Statements of Cash Flows


Years ended December 31,	2021		2020		2019
	(In thousands)
Net cash provided by operating activities	$	187,297	$	226,642	$	168,520
Investing activities:
Investments in and advances to subsidiaries	(102,000)		(67,000)		(120,000)
Advances from subsidiaries	—		—		17,000
Investments	(391)		(4)		(236)
Net cash used in investing activities	(102,391)		(67,004)		(103,236)
Financing activities:
Proceeds from issuance of common stock	88,767		3,385		106,848
Dividends paid	(171,354)		(166,405)		(160,256)
Repurchase of common stock	(2,992)		—		—
Tax withholding on stock-based compensation	(1,949)		(163)		(1,821)
Net cash used in financing activities	(87,528)		(163,183)		(55,229)
Increase (decrease) in cash and cash equivalents	(2,622)		(3,545)		10,055
Cash and cash equivalents - beginning of year	8,781		12,326		2,271
Cash and cash equivalents - end of year	$	6,159	$	8,781	$	12,326

The accompanying notes are an integral part of these condensed financial statements.

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, 2021, 2020 and 2019. 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 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 At December 31, 2021, the Company had no long-term debt maturities. For more information on debt, see Item 8 - Note 9.

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 $188.1 million, $228.4 million and $177.1 million for the years ended December 31, 2021, 2020 and 2019, respectively.

120 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

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)

Fifth Amended and Restated Credit Agreement, dated as of December 19, 2019, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Several Financial Institutions party thereto

10-K

12/31/19

4(c)

2/21/20

1-03480

*4(d)

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(e)

Centennial Energy Holdings, Inc. Note Purchase Agreement, dated December 20, 2012, among Centennial Energy Holdings, Inc. and various purchasers of the notes

10-Q

6/30/19

4(a)

8/2/19

1-03480

4(f)

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(g)

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(h)

WBI Energy Transmission, Inc. Amended and Restated Note Purchase and Private Shelf Agreement, effective as of September 12, 2013, among Prudential Investment Management, Inc. and certain investors described therein

10-K

12/31/20

4(h)

2/19/21

1-03480

4(i)

Amendment No. 1 to WBI Energy Transmission, Inc. Amended and Restated Note Purchase and Private Shelf Agreement, dated May 17, 2016, among Prudential Investment Management, Inc. and certain investors described therein

10-K

12/31/20

4(i)

2/19/21

1-03480

4(j)

Amendment No. 2 to WBI Energy Transmission, Inc. Amended and Restated Note Purchase and Private Shelf Agreement, dated July 26, 2019 and effective May 16, 2019, among Prudential Investment Management, Inc. and certain investors described therein

10-K

12/31/20

4(j)

2/19/21

1-03480

+10(a)

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(b)

MDU Resource Group, Inc. Director Compensation Policy, as amended May 12, 2021

10-Q

6/30/21

10(b)

8/5/21

1-03480

+10(c)

Deferred Compensation Plan for Directors, as amended May 15, 2008

10-Q

6/30/08

10(a)

8/7/08

1-03480

+10(d)

Non-Employee Director Stock Compensation Plan, as amended May 12, 2011

10-Q

6/30/11

10(a)

8/5/11

1-03480

+10(e)

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

+10(f)

MDU Resources Group, Inc. Long-Term Performance-Based Incentive Plan, as amended February 11, 2016

10-K

12/31/15

10(f)

2/19/16

1-03480

+10(g)

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

MDU Resources Group, Inc. Form 10-K 121

Index

Part IV

Incorporated by Reference

Exhibit Number

Exhibit Description

Filed Herewith

Form

Period Ended

Exhibit

Filing Date

File Number

+10(h)

Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 14, 2019

10-K

12/31/18

10(k)

2/22/19

1-03480

+10(i)

Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 13, 2020

10-K

12/31/19

10(k)

2/21/20

1-03480

+10(j)

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(k)

Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 17, 2022

+10(l)

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(m)

Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 17, 2022

+10(n)

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(o)

Form of Amendment No. 1 to Indemnification Agreement, dated May 15, 2014

8-K

10.2

5/15/14

1-03480

+10(p)

MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of February 6, 2021

10-K

12/31/20

10(q)

2/19/21

1-03480

+10(q)

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(r)

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(s)

MDU Resources Group, Inc. Deferred Compensation Plan Document, dated November 12, 2020

8-K

10.2

11/12/20

1-03480

+10(t)

Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated December 17, 2020

10-K

12/31/20

10(u)

2/19/21

1-03480

+10(u)

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(v)

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(w)

MDU Resources Group, Inc. 401(k) Retirement Plan, as amended January 1, 2022

+10(x)

Employment Letter for Jeffrey S. Thiede, dated May 16, 2013

10-K

12/31/13

10(ab)

2/21/14

1-03480

+10(y)

Jason L. Vollmer Offer Letter, dated September 20, 2017

8-K

10.1

9/21/17

1-03480

Subsidiaries of MDU Resources Group, Inc.

Consent of Independent Registered Public Accounting Firm

31(a)

Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)

Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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

Mine Safety Disclosures

122 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

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


* 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.


Item 16. Form 10-K Summary

None.

MDU Resources Group, Inc. Form 10-K 123

Index

Part IV

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		MDU Resources Group, Inc.

Date:	February 23, 2022	By:	/s/ David L. Goodin
			David L. Goodin
			(President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the date indicated.


Signature	Title	Date

/s/ David L. Goodin	Chief Executive Officer and Director	February 23, 2022
David L. Goodin
(President and Chief Executive Officer)

/s/ Jason L. Vollmer	Chief Financial Officer	February 23, 2022
Jason L. Vollmer
(Vice President and Chief Financial Officer)

/s/ Stephanie A. Barth	Chief Accounting Officer	February 23, 2022
Stephanie A. Barth
(Vice President, Chief Accounting Officer and Controller)

/s/ Dennis W. Johnson	Director	February 23, 2022
Dennis W. Johnson
(Chair of the Board)

/s/ Thomas Everist	Director	February 23, 2022
Thomas Everist

/s/ Karen B. Fagg	Director	February 23, 2022
Karen B. Fagg

/s/ Patricia L. Moss	Director	February 23, 2022
Patricia L. Moss

/s/ Dale S. Rosenthal	Director	February 23, 2022
Dale S. Rosenthal

/s/ Edward A. Ryan	Director	February 23, 2022
Edward A. Ryan

/s/ David M. Sparby	Director	February 23, 2022
David M. Sparby

/s/ Chenxi Wang	Director	February 23, 2022
Chenxi Wang

124 MDU Resources Group, Inc. Form 10-K