Other electric revenues, which are largely transmission-related revenues, for Montana-Dakota were $38.1$38.8 million, $30.4$23.0 million and $11.8$38.1 million for the years ended December 31, 2017, 20162019, 2018 and 2015,2017, respectively.

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

Retail electric rates, service, accounting and certain security 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 are 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 and other matters.

Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its interconnected system. MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from that market.

In June 2016, Montana-Dakota and a partner began construction on a 345-kilovolt transmission linethe BSSE project within the footprint of MISO from Ellendale, North Dakota, to Big Stone City, South Dakota, a distance of about 160 miles, which will facilitate public policy goals and objectives, including delivery of renewable wind energy from North Dakota to eastern markets.MISO. The project has been approved as a MISO multivalue project. All necessary easements have been secured and the project is expected to be completed incommenced on-line operations on February 5, 2019.

Approximately 2426 percent of the electricity delivered to customers from Montana-Dakota's owned generation in 20172019 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 theits electric generation resource fleet has been reduced by more than 25approximately 31 percent since 2003 and is expected to continue to decline.

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 61,50163,686 kW in July 2012.2018. 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 itsMontana-Dakota's Sheridan-area customers.

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

The owners of Big Stone Station, including Montana-Dakota, have a coal supply agreements, whichagreement with Peabody COALSALES, LLC to meet a portionall of the Big Stone Station's fuel requirements for the purchase of 250,000 tons in 2018 and 2019 from Contura Coal Sales, LLC and 550,000 tons in 2018 from Peabody COALSALES, LLC both at contracted pricing. The remainder of2020. Montana-Dakota estimates the Big Stone Station fuel requirements willcoal supply agreement to be secured through separate future contracts.approximately 1.6 million tons for 2020.

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 585,000 tons.

The average cost of coal purchased, including freight, at Montana-Dakota's electric generating stations (including the Big Stone, Coyote and Wygen III stations) was as follows:

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 2024.2020. In February 2019, Montana-Dakota announced that it intends to retire three aging coal-fired electric generating units. The retirements are expected to be completed in early 2021 for Lewis & Clark Station and early 2022 for units 1 and 2 at Heskett Station. Montana-Dakota also announced the intent to construct a new simple-cycle natural gas-fired combustion turbine peaking unit at the existing Heskett Station. Future capacity that is needed to replace contracts, generation retirements and meet system growth requirements is 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 in varying degrees,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.

For the Thunder Spirit Wind project, Montana-Dakota implemented a renewable resource cost adjustment rider, and all of Montana-Dakota's wind resources pertaining to North Dakota electric operations were placed in this rider upon a final order of the most recent North Dakota electric general rate case. Montana-Dakota also has in place in North Dakota a transmission tracker to recover transmission costs associated with MISO and the Southwest Power Pool, regional transmission systemsorganizations serving Montana-Dakota,parts of Montana-Dakota's system, 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 the Thunder Spirit Wind project 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 the Southwest Power Pool, regional transmission systemsorganizations serving Montana-Dakota,parts of Montana-Dakota's system, along with certain of the transmission investments not recovered through retail rates. TheThis tracking mechanism also has an annual true-up.

In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, the increases associated with its allocated share of Montana state and localproperty-related taxes assessed to electric operations on an after taxafter-tax basis.

For more information on regulatory matters, see Item 8 - Note 16.19.

Montana-Dakota's electric generating facilities have Title V Operating Permits, under the 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 Permit renewal application for Big Stone Station was submitted timely to the South Dakota DENR in November 2013, and a final permit was issued in May 2017. An application to modify the Title V Operating Permit for incorporation of two new natural gas-fired engines at Lewis & Clark Station was submitted to the Montana DEQ timely in December 2016, and a final permit was issued in July 2017. The Title V Operating Permit renewal application for Coyote Station was submitted timely to the North Dakota Department of Health in September 2017, with the permit expected to be issued in 2018.issuance date not specified at this time. Wygen III is allowed to operate under the facility's construction permit until the Title V Operating Permit is issued by the Wyoming Department of Environmental Quality. The Title V Operating Permit application for Wygen III was submitted timely in January 2011, with the permit issuance date not specified at this time. The Title V Operating Permit renewal application for Heskett Station was submitted timely in June 2019 to the North Dakota Department of Environmental Quality with the permit expected to be issued in 2018.2020. The Title V Operating Permit renewal application for Lewis & Clark

State water discharge permits issued under the requirements of the 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 conditionally exemptvery small-quantity generators of hazardous waste generators and subject only to minimum regulation under the RCRA. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.

Transportation and other revenues for the natural gas distribution operations were $62.8$65.8 million, $59.6$54.4 million and $58.5$62.8 million for the years ended December 31, 2019, 2018 and 2017, 2016 and 2015, respectively.

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 security issuances.

Competition in varying degreesresulting 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 services 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 did not have a material effect on results of operations.

The natural gas distribution operations and various distribution transportation customers obtain 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, TransCanada Corporation, Northern Natural Gas, Gas Transmission Northwest LLC, Northwestern Energy, Viking Gas Transmission Company, Enbridge Westcoast EnergyPipeline, Inc., Ruby Pipeline LLC, Foothills Pipe Lines Ltd. and NOVA Gas Transmission Ltd. 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, Company,LLC, Northwest Pipeline LLC, Northwest Natural Gas Company 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 natural gas distribution operations believe that, based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available through their suppliers and pipeline service providers, supplies are adequate to meet their system natural gas requirements for the next decade.

Montana-Dakota's North Dakota and South Dakota natural gas tariffs contain weather normalization mechanisms applicable to certain firm customers that adjust the distribution delivery charge revenues to reflect weather fluctuations during the November 1 through May 1 billing periods.

In Montana, Montana-Dakota recovers in rates, through a tracking mechanism, the increases associated withits allocated share of Montana state and localproperty-related taxes assessed to natural gas operations on an after taxafter-tax basis.

On December 28, 2015, the OPUC approved an extension of Cascade's decoupling mechanism until January 1, 2020, with an agreement that Cascade would initiate a review of the mechanism by September 30, 2019. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC. Cascade initiated the required review by September 30, 2019, which resulted in a slight modification to the mechanism. The decoupling mechanism was approved to continue until January 1, 2025, with a review to be initiated by September 30, 2024.

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. The decoupling mechanism will be reviewed following the end of 2019.in 2020.

On December 22, 2016, the MNPUC approved a request by Great Plains to implement a full revenue decoupling mechanism pilot project.project for three years. The decoupling mechanism will reflect the period OctoberJanuary 1 through September 30December 31. Great Plains requested approval to extend the initial pilot period through 2020 with the first adjustmenta final determination to be billed to customers effective December 1 each year for the 3 year pilot project.made as part of its pending rate case.

For more information on regulatory matters, see Item 8 - Note 16.19.

The Company's natural gas distribution operations are conditionally exemptvery small-quantity generators of hazardous waste, generators and subject only to minimum regulation under the RCRA. 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 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.

The natural gas distribution operations did not incur any material environmental expenditures in 2017.2019. 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 2020.2022.

Montana-Dakota and Great Plains havehas ties to six historic manufactured gas plants as a successor corporation or through direct ownership of the plant. Montana-Dakota is investigating onepossible soil and groundwater impacts due to the operation of two of these former manufactured gas plant sites and providing input on another site investigation conducted by a third party.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 three of these manufactured gas plants in Washington and Oregon. See Item 8 - Note 17 for a further discussion of these three manufactured gas plants. To the extent not covered by insurance, Cascade will seek recovery of investigation and remediation costs through its natural gas rates charged to customers.

The nonregulated business of this segment owns and operates gathering facilities in Montana and Wyoming. In total, facilities include approximately 800 miles of operated field gathering lines, some of which interconnect with WBI Energy's regulated pipeline system. The nonregulated business provides natural gas gathering services and a variety of other energy-related services, including cathodic protection and energy efficiency product sales and installation services to large end-users. In November 2016, the Company entered into an agreement to sell its ownership in the Pronghorn assets, which included a 50 percent undivided interest in a natural gas processing plant, both oil and gas gathering pipelines, an oil storage terminal and an oil pipeline in western North Dakota. The transaction closed in January 2017.

WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf, including 193194 Bcf of working gas capacity, 8584 Bcf of cushion gas and 75 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, storage and gathering business and at times may discount rates in an effort to retain market share. However, the strategic location of its system near fivefour natural gas producing basins and the availability of underground storage and gathering services, along with interconnections with other pipelines, serve to enhance 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 20172019 represented 3427 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the firm transportation agreements with Montana-Dakota expire in June 2022. In addition, Montana-Dakota has contracts, expiring in July 2035, with WBI Energy Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements expiring in July 2035.requirements.

The nonregulated business competes for existing customers in the fieldsareas in which it operates. Its focus on customer service and the variety of services it offers serve to enhance its competitive position.

Ongoing operations are subject to the Clean Air Act, the Clean Water Act, the RCRA and other state and federal regulations. Administration of manycertain provisions of thesefederal environmental laws has been delegated to the states where WBI Energy and its subsidiaries operate. PermitAdministering agencies may issue permits with varying terms vary and all permits carry operational compliance conditions. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand, facility upgrades or modifications, and/or regulatory changes. The Company believes it is in substantial 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.

Knife River's backlog was approximately $486$693 million, $538$706 million and $491$486 million at December 31, 2019, 2018 and 2017, 2016 and 2015, respectively. The decrease in backlog at December 31, 2017, compared to backlog at December 31, 2016, was primarily attributable to a lower backlog of state agency work. Backlog increases with awards of new contracts and decreases as work is performed on existing contracts. Knife River expects to complete a significant amount of the backlog at December 31, 2017,2019, during the next 12 months. For more information on backlog including the timing of revenue recognition, see Item 8 - Note 2.

Knife River's backlog is comprised of the anticipated revenues from the uncompleted portion of services to be performed under job-specific contracts. A project is included in backlog when a contract is awarded and agreement on contract terms has been reached. However, backlog does not contain contracts for time and material projects that a fixed amount cannot be determined. Backlog is comprised of: (a) original contract amounts, (b) change orders for whichapproved by customers have approved and (c) claim amounts that have beenclaims made against customers, for which are determined to have a legal basis under existing contractual arrangements, and as tothe amount for which recovery is considered to be probable. Such claim amounts were immaterial for all periods presented. Backlog may be subject to delay, default or cancellation at the election of the customers. Historically, cancellations have not had a materially adverse effect on backlog. Due to the nature of its contractual arrangements,

in many instances Knife River's customers are not committed to the specific volumes of services to be purchased under a contract, but rather Knife River is committed to perform these services if and to the extent requested by the customer. Therefore, there can be no assurance as to the customers' requirements during a particular period or that such estimates, or backlog estimates in general, at any point in time are predictive of future revenues.

The demand for construction materials products and contracting services is significantly influenced by the cyclical nature of the construction industry in general. In addition, construction materials and contracting services 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 both the commercial and residential sectors, and prevailing interest rates.

Knife River's customers are a diverse group which includes federal, state and municipal government agencies, commercial and residential developers, and private parties. The mix of sales by customer will vary each year depending on the work available. 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.

Estimates are based on analyses of the data described above by experienced internal mining engineers, operating personnel and geologists. 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. 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 the 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.

Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. 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 891978 million tons of the 965 million1.1 billion tons of aggregate reserves are permitted reserves. 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 years remaining were calculated by dividing remaining reserves by the three-year average sales, including estimated sales from 2015acquired reserves prior to acquisition, from 2017 through 2017.2019. 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 changes in Knife River's aggregate reserves for the years ended December 31 were as follows:

Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to the Clean Air Act and the Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities are also are subject to these laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities are also are subject to the RCRA as it applies to the management of hazardous wastes and

underground storage tank systems. These programs also have generally been 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.

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

Knife River's operations are also are 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 are 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.

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 taking into accountconsidering 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 permit approvals 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's intention is to request bond release as soon as it is deemed possible.

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 17.20.

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’ backlog at December 31 was as follows:

The increase in backlog at December 31, 2017,2019, compared to backlog at December 31, 2016,2018, was primarilylargely attributable to an increasethe new project opportunities that MDU Construction Services continues to be awarded across its diverse operations, particularly inside specialty electrical and mechanical contracting in projects from all revenue streams based on customer demand.the hospitality, high-tech, mission critical and public industries. MDU Construction Services' outside power, communications and natural gas specialty contracting also have a high volume of available work. Backlog increases with awards of new contracts and decreases as work is performed on existing contracts. MDU Construction Services expects to complete a significant amount of the backlog at December 31, 2017,2019, during the next 12 months. Additionally, MDU Construction Services continues to further evaluate potential business combination opportunities that would be accretive to its business and grow its backlog. For more information on backlog including the timing of revenue recognition, see Item 8 - Note 2.

MDU Construction Services’ backlog is comprised of the anticipated revenues from the uncompleted portion of services to be performed under job-specific contracts. A project is included in backlog when a contract is awarded and agreement on contract terms has been reached. However, backlog does not contain contracts for time and material projects that a fixed amount cannot be determined. Backlog is comprised of: (a) original contract amounts, (b) change orders for whichapproved by customers, have approved, (c) pending change orders expected to receive confirmation in the ordinary course of business and (d) claim amounts that have beenclaims made against customers, for which are determined to have a legal basis under existing contractual arrangements, and as tothe amount for which recovery is considered to be probable. Such claim amounts were immaterial for all periods presented. Backlog may be subject to delay, default or cancellation at the election of the customers. Historically, cancellations have not had a material adverse effect on backlog. Due to the nature of its contractual arrangements, in many instances MDU Construction Services' customers are not committed to the specific volumes of services to be purchased under a contract, but rather MDU Construction Services is committed to perform these services if and to the extent requested by the customer. Therefore, there can be no assurance as to the customers' requirements during a particular period or that such estimates, or backlog estimates in general, at any point in time are predictive of future revenues.

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 to a certain extent 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 these customers.

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.

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 that it filesfiled with the SEC. The factors and the 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.

There can be no assurance that applicable regulatory commissions will determine all the costs ofthat the Company's electric and natural gas transmission and distribution businesses tobusinesses' costs have been prudent, which could result in disallowance of costs. Also, the regulatory process for approval ofapproving rates for these businesses may not result inallow for timely and full recovery of the costs of providing services.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 relief for these types of retirements, there is no assurance the regulators will allow full recovery of all remaining costs, leavingwhich 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 their customers.

Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirerneeded 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 deferdeter potential acquirers from approaching the Company or impact the Company's ability to pursue otherwise attractive acquisitions.

The ability ofEconomic conditions and population growth affect the Company's electric and natural gas distribution businesses to growbusinesses' growth in service territory, customer base and usage demand is affected bydemand. Economic volatility in the markets served, along with economic environments and population growthconditions such as increased unemployment, which

could impact the ability of the markets served. This economic volatilityCompany's customers to make payments, could have a material adverse effect onadversely affect the Company's results of operations, cash flows and asset values. Further, any material decreases in customers' energy demand, by customers, for economic or other reasons, could have a material adverse impact on the Company's earnings and results of operations.

The Company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyondA disruption of the regional electric transmission grid or interstate natural gas infrastructure could negatively impact the Company's control. If the Company is unable to obtain cost effective financing in the future,business and reputation. Because the Company's ability to execute its business plans, make capital expenditures or pursue acquisitions that the Company may otherwise rely on for future growthelectric and natural gas utility and pipeline systems are part of larger interconnecting systems, a disruption could be impaired. Asresult in a result, the market value of the Company's common stock may be adversely affected. If the Company issues a substantial amount of common stock itsignificant decrease in revenues and system repair costs, which could have a dilutive effectmaterial impact on its existing shareholders.the Company's financial position, results of operations and cash flows.

The issuance of a substantial amount of the Company's common stock, whether issued in connection with an acquisition or otherwise, could have a dilutive effect on existing shareholders, 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.

Severe weather events may damage or disrupt the Company's electric and natural gas transmission and distribution facilities, which could increase costs to repair facilities and restore service to customers. The cost of providing service could increase to the extent the frequency of severe weather events increases because of climate change or otherwise. The Company may also have indirect credit risk duenot recover all costs related to participationmitigating these physical risks.

Severe weather may result in energy markets such as MISO in which credit losses are socialized to all participants.

Increases in severe weather conditions or extreme temperature may cause infrastructure construction projects to the Company. The Company continues to examine the impact the TCJA may have on the Companybe delayed or canceled and limit resources available for such projects resulting in future periods. The TCJA's impact on the economy, including overall demand and competition for the products and services the Company provides and associated labor availability anddecreased revenue or increased project costs is unknown and there could be negative impacts to the Company. The Company's utility businesses' cash flows may be negatively impacted by the disallowance of immediate expensing of utility property. Other changes to federal and state 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 resourcesconstruction materials and the resource selection for the electric generation business. Regulation incorporates

changes in tax law intocontracting and construction services businesses. In addition, drought conditions could restrict the rate setting process foravailability of water supplies, inhibiting the regulated energy deliveryability of the construction businesses and therefore could create timing delays before the impact of changes are realized.

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 changes may require the Company to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes 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 weather conditions creatingtemperatures may create high energy demand mayand raise electricity prices, which wouldcould 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 has also been adversely affected by severe weather events which may impact the availability of insurance coverage, insurance premiums and insurance policy terms.

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 Clean Air Act, 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. 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 cause less than ideal terms and conditions.

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.

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/or property damage, which could require additional costsremediation 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 be incurred.

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 3525 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 also depend upon one or more factors including the outcome of collective bargaining,bargaining; actions taken by trustees who manage the plans,plans; actions taken by the plans' other participating employers,employers; the industry for which contributions are made,made; future determinations that additional plans reach endangered, seriously endangered or critical status,status; newly-enacted government laws or regulations and the actual return on assets held in the plans,plans; among others. The Company maycould experience increased operating expenses as a result of the required contributions to MEPPs, which maycould have a material adverse effect on the Company's results of operations, financial position or cash flows.

In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan to the extent these plans are underfunded.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.

Information technology disruptions or cyberattacks could adversely impact the Company's operations.

The Company’s accounting systems and its ability to collect information and invoice customers for products and services could also be disrupted. If the Company’s operations were disrupted, it could result in decreased revenues or significant remediation costs that could have a material adverse effect on the Company's results of operations and cash flows. Additionally, because electric generation and transmission systems and natural gas pipelines are part of interconnected systems with other operators’ facilities, a cyber-related disruption in another operator’s system could negatively impact the Company's business.

The Company, through the ordinary course of business, requires access to sensitive customer, employee and Company data. While the Company has implemented extensive security measures, a breach of its systems could compromise sensitive data.data and could go unnoticed for some time. In addition, there has been an increase in the number and sophistication of cyber-attacks across all industries worldwide and the threats are continually evolving. 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 have an adverse effect on the Company.

The Company’s information systems experience on-going and often sophisticated cyber-attacks by a variety of sources with the apparent aim to breach the Company's cyber-defenses. As cyber-attacks continue to increase in frequency and sophistication, the Company may be subjectunable to potential material liabilities relating toprevent all such attacks in the past sale of assets or businesses, primarily arising from events prior to sale.

The Company has no unresolved comments with the SEC.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly dividends for more than 80 consecutive years with an increase in the payout amount for the last 29 consecutive years. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements, 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 9.12.

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