NACCO Industries (NC) 10-K2020 FY Annual report

NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913.

The Company has continued to operate as an essential business during the COVID-19 pandemic because it supports critical infrastructure industries. The extent to which COVID-19 impacts the Company going forward will depend on numerous factors and future developments that remain uncertain.

The Company is leveraging its core mining and natural resources management skills to develop a strong and diverse portfolio of affiliated businesses operating in the mining and natural resources industries while maintaining a conservative capital structure. Diversified strategic growth is the key to enhancing net income as well as increasing free cash flow available to continue to reinvest in and expand the businesses.

NAMining continues to expand the scope of its business development activities to grow and diversify by targeting geographically diverse customers who require a broad range of minerals and materials. NAMining also continues to leverage the Company’s core mining skills to expand the range of contract mining services provided, in addition to providing comprehensive mining services to operate entire mines when appropriate, such as the long-term mining contract with Lithium Americas to provide mining services for its Thacker Pass lithium project in Nevada.

The Company’s efforts to grow and diversify the Minerals Management segment include acquiring additional mineral interests or similar investments in the energy industry. Once mineral and royalty interests have been acquired, the Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development.

MRNA creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation. This business offers opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise. MRNA has achieved impressive initial growth and is positioned for additional growth.

One of the Company’s core strategies is to pursue activities which can provide resiliency to its existing coal mining

operations. The Company works to drive down coal production costs and maximize efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers.

The Company evaluates opportunities to expand its coal mining business, but opportunities are few. Low natural gas prices and growth in renewable energy sources, such as wind and solar, are likely to continue to unfavorably affect the amount of electricity dispatched from coal-fired power plants. The political and regulatory environment is not receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines. However, the Company would consider opportunities where it can apply its management fee business model to assume operation of existing

surface coal mining operations in the United States. Outright acquisitions of existing coal mines or mining companies with exposure to fluctuating coal commodity markets, or structures that would create significant leverage, are outside the Company’s area of focus.

In all of its business endeavors, the Company continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety, environmental stewardship and people.

During 2020, the Minerals Management segment acquired mineral interests for approximately 65.5 thousand gross acres and 1.2 thousand net royalty acres in the Permian Basin in Texas for a total purchase price of approximately $14.2 million. The acquired interests align with the Company’s strategy of selectively acquiring mineral interests with a balance of near-term cash flow yields and long-term growth potential, in oil-rich basins offering diversification from the Company’s legacy mineral interests in predominately natural gas-rich basins.

The Sabine Mining Company (“Sabine”) operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W. Pirkey Plant (the “Pirkey Plant”). SWEPCO is an American Electric Power (“AEP”) company. On November 5, 2020, AEP announced it intends to retire the Pirkey Plant in 2023 in order to comply with the U.S. Environmental Protection Agency’s Coal Combustion Residuals rule. The Sabine Mine delivered 1.9 million and 2.6 million tons to the Pirkey Plant in 2020 and 2019, respectively. During 2020, SWEPCO reduced its expected future annual delivery requirements to be between 1.4 million and 1.7 million tons. The Sabine Mine contributed $3.9 million and $4.6 million to NACCO’s Earnings from Unconsolidated Operations during 2020 and 2019, respectively.

The Coteau Properties Company (“Coteau”) operates the Freedom Mine in North Dakota. All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative (“Basin Electric”). Basin Electric utilizes the coal at the Great Plains Synfuels Plant (the “Synfuels Plant”), Antelope Valley Station and Leland Olds Station. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. On November 5, 2020, Basin Electric informed its employees and Coteau that it is considering changes that may result in modifications to its Synfuels Plant that could potentially reduce or eliminate coal requirements at the Synfuels Plant beginning in 2026. Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026. As a result, coal deliveries to the Synfuels Plant are expected to continue until at least 2026.

On September 30, 2020, Caddo Creek Resources Company, LLC's (“Caddo Creek's”) customer, a division of Cabot Corporation, entered into a long-term supply agreement with a subsidiary of Advanced Emissions Solutions (“AES”) as well as an agreement for the sale of the Marshall Mine, operated by Caddo Creek, to a subsidiary of AES. AES announced its intent to close the Marshall Mine. Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation. The Marshall Mine delivered 0.1 million and 0.2 million tons during 2020 and 2019, respectively.

The contract mining agreement between Camino Real Fuels, LLC (“Camino Real”) and its customer, Dos Republicas Coal Partnership (“DRCP”), terminated effective July 1, 2020 as a result of the unexpected termination by Comisión Federal de Electricidad (“CFE”) of its coal supply contract with an affiliate of DRCP. The termination of the contract between CFE and DRCP eliminated DRCP’s need for coal from Camino Real's Eagle Pass Mine, and resulted in mine closure. Mine reclamation is the responsibility of DRCP. Camino Real has no legal obligation to perform mine reclamation. The Eagle Pass Mine delivered 0.3 million and 1.6 million tons during 2020 and 2019, respectively.

On May 7, 2020, Great River Energy ("GRE"), Falkirk Mine's customer, announced its intent to retire the Coal Creek Station power plant in the second half of 2022 and modify the Spiritwood Station power plant to be fueled by natural gas. As noted in the announcement, GRE is willing to consider opportunities to sell Coal Creek Station. Falkirk Mine is the sole supplier of lignite coal to Coal Creek Station pursuant to a long-term contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station. Falkirk delivered a total of 7.2 million and 7.4 million tons of lignite coal and contributed $16.1 million and $15.9 million to NACCO’s Earnings from Unconsolidated Operations during 2020 and 2019, respectively.

In 2019, NAMining, through a new subsidiary, Sawtooth Mining, entered into a mining agreement to serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada. The Thacker Pass Project is 100% owned by Lithium Nevada Corp, a subsidiary of Lithium Americas Corp. Lithium Nevada plans to develop a lithium production facility near what is believed to be the largest known lithium deposit in the United States. Sawtooth Mining will provide comprehensive mining services similar to the Company's typical scope of work in the Coal Mining segment. The mining agreement provides that

Lithium Nevada will reimburse Sawtooth Mining for its operating and mine reclamation costs, and pay Sawtooth Mining a management fee per metric ton of lithium delivered during the 20-year contract term commencing with receipt of construction and operating permits by Lithium Nevada.

During 2020, the Company's operating coal mines were: Bisti Fuels Company, LLC (“Bisti”), Caddo Creek, Camino Real, Coteau, Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), Falkirk, Mississippi Lignite Mining Company (“MLMC”) and Sabine.

Coteau, Coyote, Falkirk, MLMC and Sabine supply lignite coal for power generation. Bisti supplies sub-bituminous coal for power generation. Demery supplies lignite coal for the production of activated carbon. Each of these mines deliver their coal production to adjacent or nearby power plants, synfuels plants or an activated carbon processing facility under long-term supply contracts. Each mine is the exclusive supplier of coal to its customers' facilities. MLMC’s coal supply contract contains a take or pay provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate. In addition, certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

At all operating coal mines other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to NACCO and NACoal. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

All operating coal mines other than MLMC meet the definition of a variable interest entity (“VIE”). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s investment is reported on the line Investments in Unconsolidated Subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the “Unconsolidated Subsidiaries.” For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return; therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, the persistence of low diesel fuel prices can negatively affect earnings at MLMC.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA.

The coal reserves at Coteau, Falkirk, Coyote, MLMC and Centennial Natural Resources ("Centennial") are owned or controlled by the Company. The coal reserves at all other mines are owned or controlled by the respective mine’s customer. Total coal reserves approximate 1.9 billion tons (including the unconsolidated coal mining subsidiaries), with approximately 0.7 billion tons committed to customers pursuant to long-term contracts.

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under

certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The segment is a primary platform for the Company’s growth and diversification of mining activities outside of the coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining operates primarily at limestone quarries in Florida, but is focused on expanding outside of Florida and into mining materials other than limestone. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

NAMining utilizes both fixed price and management fee contract structures. Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals.

Total consideration for the 2020 acquisitions of mineral and royalty interests was $14.2 million, of which $12.0 million closed in December 2020, $2.0 million closed in November 2020 and $0.2 million closed in August 2020. The acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres. The Company did not acquire any mineral interests in 2019. Including the 2020 acquisitions, total mineral and royalty interests include approximately 109.2 thousand gross acres and 58.1 thousand net royalty acres.

The Company’s legacy royalty and mineral interests are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.

The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests, and overriding royalty interests.

The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not have any investments under which it would be required to bear the cost of exploration, production or development.

As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. Consequently, the exact number of wells producing from or drilling on the Company’s mineral interests at a given point in time is not determinable. The following table sets forth information about Company’s best estimate of the number of gross and net productive wells as of December 31, 2020:

Gross wells are the total wells in which an interest is owned.

Net wells are the sum of the fractional interest owned in gross wells.

The majority of the Company’s producing mineral and royalty interest acreage is, or in the future, can be pooled with third-party acreage to form pooled units. Pooling proportionately reduces the Company’s royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which the Company has such reduced royalty interest.

The principal customers of the Coal Mining segment are electric utilities, an independent power provider and a producer of activated carbon.

The principal customers of the NAMining segment are limestone producers. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace

and can fluctuate considerably. As a royalty owner and non-operator, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

In 2020, two customers individually accounted for more than 10% of consolidated revenue. In 2019, two customers and an oil and gas lessee individually accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:

The loss of either of these customers or the lessee could have a material adverse effect on the results of operations attributable to the applicable segment and on the Company's consolidated results of operations.

In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. For the year ended December 31, 2020, the Coal Mining segment derived approximately 60% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE. GRE announced its intent to close Coal Creek station in 2022. The loss of either of these contracts could have a material adverse effect on the Earnings of Unconsolidated Operations of the Coal Mining segment and a material adverse effect on the Company's Consolidated Statements of Operations.

The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems. All of the mines in the Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal being mined.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on renewable pricing and the Company's customers' dispatch decisions, which may take into account carbon dioxide emissions. The ability of the Coal Mining Segment to maintain comparable levels of coal production at existing facilities and to market and develop its reserves will depend upon the interaction of these factors.

Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Sustained low natural gas prices have resulted in an increase in electricity generated from natural gas leading to a decline in the use of coal-fired capacity in the United States. Natural gas-fired power plants have the most potential to continue to displace coal-fired electric baseload power generation in the near term. There also continues to be an increase in the amount of electricity generated by wind and solar. As an example, the Company estimates wind capacity in North Dakota has increased over 60% since 2015 to approximately 3,600 megawatts and wind developers have expressed an interest in building more than 3,000 megawatts of additional wind generation in North Dakota over the next several years. Federal and state mandates for increased use of electricity derived from renewable energy sources have also negatively affected demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources competitive with coal. The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction begins in 2021. The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025. Solar energy property placed in service after December 31, 2025 receives only a 10% ITC.

Certain of the Coal Mining segment's customers continue to invest in efficiency and environmental upgrades to their facilities. Because the Coal Mining segment's customers’ power plants are competitive suppliers of electricity in their respective dispatch

areas relative to other coal-fired generating units in those dispatch areas, the Company considers its surface coal mining operations to be well positioned relative to most other mines servicing coal-fired generating units.

Based on industry information, the Company believes it was one of the five largest coal producers in the U.S. in 2020 based on total coal tons produced.

NAMining faces competition from aggregates producers which choose to self-perform mining operations and from other mining companies.

In the Minerals Management segment, the oil and gas industry is intensely competitive; the Company primarily competes with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and who may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than the Company’s financial or human resources permit. Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals Management segment’s ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial and human resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.

The Company has experienced limited variability in its results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns. The NAMining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions and pandemics, all of which can result in variations in limestone demand.

In the Minerals Management segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of the Company's control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

As of December 31, 2020, the Company and its subsidiaries had approximately 2,000 employees, including approximately 1,500 employees at the Company’s unconsolidated mining operations, of which 261 are represented by a union at Bisti. NACCO believes it has good relations with both union and non-union employees.

NACCO believes its employees are critical to its success and invests in its employees by offering a competitive total rewards package that includes a combination of salaries and wages, health and wellness benefits, retirement benefits and educational benefits. The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. The Company recognizes the sustainability of its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments to capitalize on the skills, talents and potential of each employee. The Company believes in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability. Employee safety in the workplace is one of the Company’s core values. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company supports its local communities and is committed to helping them remain safe, healthy and resilient. The Company's past activities include corporate donations, volunteerism and education.

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available, free of charge, through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The content of the Company's website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to the Company's website is intended to be inactive textual references only.

Under Rule 12b-2 of the Exchange Act, the Company qualifies as a “smaller reporting company” because its public float as of the last business day of the Company’s most recently completed second quarter was less than $250 million. For as long as the Company remains a “smaller reporting company,” it may take advantage of certain exemptions from the SEC’s reporting requirements that are otherwise applicable to public companies that are not smaller reporting companies.

The following map shows the Coal Mining segment's locations:

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota. The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

The reserves are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

The Navajo Mine is located approximately 25 miles southwest of Farmington, New Mexico, off Indian Service Road 3005, and is on the Navajo Nation. Access to the Navajo Mine is by means of a paved road. Bisti has no title, claim, lease or option to acquire any of the reserves at Navajo Mine. NTEC, a wholly-owned limited liability company of The Navajo Nation, controls all of the reserves within the Navajo Mine.

replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The majority of electrical power for the draglines, shovels, coal crushers, coal conveyors and facilities generally is provided by the power generation customer for the applicable mine. Electrical power for the Sabine facilities is provided by Upshur Rural Electric Co-op. Electrical power for the Sabine dragline operating in the South Marshall permit area is provided by Southwestern Electric Power Company. Electrical power for the draglines operating in Sabine's Rusk permit area is provided by Rusk County Electric Co-op. Electrical power for the MLMC draglines and shovels is provided by 4-County Electric Power Association. The remainder of the equipment generally is powered by diesel fuel or gasoline.

The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2020 is set forth in the chart below:

All of the Company’s coal mines are surface mines that are located adjacent to, or nearby, the customer’s power plant, synfuels plant or activated carbon facility. Overburden, the material between the surface of the land and the coal seam, is removed using draglines, dozers and/or trucks and shovels, including electric rope shovels. Coal is then extracted and loaded onto haul trucks using surface miners, excavators, dozers, scrapers, backhoes and other machinery and equipment. Coal is taken to a stockpile or delivered directly to customers via conveyor or short haul rail. After mining, draglines and/or trucks and shovels are used to backfill the overburden that was removed at the beginning of the process to allow for site reclamation.

The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment. Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of the Company’s Minerals Management segment.

The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.

The Company's coal mining operations are subject to various federal environmental laws, as amended, including:

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority. With the exception of the Navajo Nation in New Mexico, which is directly regulated by the Office of Surface Mining Reclamation and Enforcement ("OSMRE") under their Indian Lands Program, all of the states where the Company has active coal mining operations have achieved primary control of enforcement through federal authorization under SMCRA.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency. These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation.

Although mining permits have stated expiration dates, SMCRA provides for a right of successive renewal. The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits; however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000.

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the “Fund”), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The fee is currently $0.08 per ton on lignite coal produced and $0.28 per ton on other surface-mined coal.

SMCRA establishes operational, reclamation and closure standards for surface coal mines. The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit. These obligations are unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the “EPA”), the U.S. Army Corps of Engineers and the OSMRE have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.

The Company does not believe there is any significant risk to the Company's subsidiaries ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.

guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits. SIPs will be required by July 31, 2021.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”. The remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations.

The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions of GHGs. The U.S. has not ratified the emission targets of the Kyoto Protocol or any other GHG agreement. Though the U.S. has not accepted these international GHG limiting treaties, numerous lawsuits and regulatory actions have been undertaken by states and environmental groups to try to force controls on the emission of carbon dioxide; or to prevent the construction of new coal-fired power plants.

The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States in June 2020 which modified the types of regulated waters by eliminating ephemeral streams and certain other isolated wetlands. The new definition is being challenged in court and if the new definition is overturned, some of the Company's operations could incur additional costs to mitigate streams and wetlands that are not currently regulated.

Bellaire is treating mine water drainage from coal refuse piles associated with two former underground coal mines in Ohio and one former underground coal mine in Pennsylvania, and is treating mine water from a former underground coal mine in Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

Bellaire was notified by the Pennsylvania Department of Environmental Protection ("DEP") during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust (the "Trust"). See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the Trust.

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids (" NGLs") are not currently regulated and are made at market prices.

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the Company’s mineral interests, which could materially adversely affect the Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or

closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company’s mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

The operations of the Company’s third-party lessee's are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which the Company operates also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of the Company’s mineral interests can produce from existing wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the Company’s mineral interests, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our royalties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level. In addition, the Biden administration has signaled the intent to stop hydraulic fracturing on federal land.

In addition, several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also

be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying the Company’s mineral interests to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying the Company’s mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations, could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying the Company’s mineral interests.

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of the Company’s properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where the Company holds minerals interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to

natural resources. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

From time to time, the Company has been the subject of administrative proceedings, litigation and investigations relating to environmental matters.

The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, the Company may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect the Company’s results of operations and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which the Company is required to conduct its operations.

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, the Coal Mining segment's customers could prematurely retire certain coal-fired generating units. Any customer's premature facility closure could have a material adverse effect on the Company’s business, financial condition and results of operations.

On May 7, 2020, Great River Energy ("GRE"), Falkirk Mine's customer, and the Company's second largest customer, announced its intent to retire the Coal Creek Station power plant in the second half of 2022 and modify the Spiritwood Station power plant to be fueled by natural gas. On November 5, 2020, American Electric Power announced its affiliate, Southwestern Electric Power Company's (“SWEPCO”), intends to retire the Henry W. Pirkey Plant (the “Pirkey Plant”) in 2023. The Sabine Mining Company, (“Sabine”) operates the Sabine Mine in Texas and all production from Sabine is delivered to SWEPCO's Pirkey Plant. See “Item 1. Business — Business Developments" on page 2 in this Form 10-K for further discussion.

State implementation of the EPA’s Regional Haze Rule (“RHR”) could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from the customers of Coyote Creek’s customer, negatively impact Coyote Creek’s customers’ net income, financial position and cash flows. The Company understands that the North Dakota Department of Environmental Quality (“NDDEQ”) could require sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures. If NDDEQ requires significant emissions controls at Coyote Station by December 31, 2028, it may not be economically feasible for Coyote Creek's customers to invest in such equipment and an early retirement of Coyote Station and the Coyote Creek mine could be necessary. NDDEQ’s state implementation plan is due to be submitted to the EPA by July 2021. Preliminary modeling favors minimal additional emissions control measures for all North Dakota sources. The Company expects NDDEQ to further evaluate additional preliminary control scenarios for regional visibility modeling in the first quarter of 2021 and prepare a draft state implementation plan available for public comment the first half of 2021.

Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (“LSA”), the Company would be obligated for payment of a "make-whole" amount to Coyote Creek’s third-party lenders. The “make-whole” amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek’s LSA is terminated on or after January 1, 2024 by Coyote Creek’s customers, the Company is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. Any decision by Coyote Creek’s customers to reduce operations or prematurely close the Coyote Creek mine would have a material adverse effect on the Company’s results of operations, financial position and cash flows.

For the year ended December 31, 2020, the Coal Mining segment derived approximately 60% of earnings of unconsolidated operations from two customers, Basin Electric Power Cooperative and GRE. GRE announced its intent to close Coal Creek station in 2022. There are inherent risks whenever a significant percentage of total earnings are concentrated with a limited number of customers. Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of the Company's control. If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See “Item 1. Business — Business Developments" on page 2 in this Form 10-K for further discussion. Further, in large part as a result of increasing and frequently changing regulation and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, electric power generators may be less willing to enter into long-term coal supply contracts. Any shift away from long-term supply contracts could adversely affect the Company's profitability, cash flows and financial position.

The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $135 million of long-lived assets, including property, plant and equipment and its coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.

MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. The price of diesel fuel is heavily-weighted among these indices. As such, a substantial decline in diesel prices could materially reduce MLMC's profitability, as the decline in revenue will only be partially offset by the effect of lower diesel prices on production costs.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to TVA under a long-term PPA. MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. In 2019, TVA published its updated Integrated Resource Plan ("IRP"). The IRP indicates TVA plans to increase its reliance on solar power. A decrease in the number of days TVA dispatches the Red Hills Power Plant would reduce MLMC's customer's demand for coal. The decision of which power plants to dispatch is determined by TVA. TVA has dispatched Red Hills Power Plant at a lower rate in 2019 and 2020 than in previous years.

Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. Southern Company recently publicly disclosed that while all CGLP lease payments have been paid in full through December 31, 2020, operational and other risks have resulted in cash liquidity challenges at the Red Hills Power Plant, and based on current forecasts of energy prices in the years following the expiration of the PPA in 2032, concerns exist regarding the lessee's ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. During the fourth quarter of 2019, Southern Company concluded that it was no longer probable that all of the payments would be received over the term of the lease and therefore recognized an impairment charge to reduce the value of the lease investment. During the second quarter of 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If any future lease payment is not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. A foreclosure of the Red Hills Power Plant could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

Similar to the Company's unconsolidated mines, all production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce its inventory carrying value using the lower of cost or net realizable value approach, which could adversely affect MLMC’s results of operations.

Changes in customer demand for any reason, including, but not limited to, reduced mechanical availability of the customer’s power plant, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Red Hills Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a "management fee" approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates.  During the production stage, the Unconsolidated Subsidiaries' customers pay the Company its agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, fluctuations in demand due to unanticipated weather conditions, scheduled and unscheduled outages at the Coal Mining segment's customers' facilities, unplanned equipment failures, economic conditions or governmental regulations or comparable policies which may promote dispatch of power generated by renewables, such as wind or solar, and the realignment of customers' power generation portfolios that reduce the electric power generated from coal could have a material adverse effect on the Company's results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce the Company's profitability.

The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.

Changes in the utility and coal mining industry that affect our customers could also adversely affect the Company. Lower natural gas prices and increased availability of renewables have contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to continue to displace a significant amount of coal-fired electric power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.

Changes in federal and state mandates that would include an acceleration in the use of electricity derived from renewable energy sources could result in a decrease in coal consumption by the electric power generation industry and the Company’s customers.

Certain of the Coal Mining segment’s customers, including MLMC's customer, benefit or have benefited from a tax credit under Section 45 of the Internal Revenue Code. The benefit results in a reduction to the cost of coal-fired electric power generation. The elimination or expiration of the Section 45 tax credit would increase the cost of the coal-fired electric power generation from these facilities and could result in the power these facilities produce being less economical than other sources of power generation, which could reduce demand and result in a decrease in coal consumption.

Any of these risks could result in a decrease in coal consumption by the Company’s customers and could have a material adverse effect on the Company’s business, financial condition and results of operations.

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental permits and approvals. The Company is required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or

regulations and orders may materially adversely affect the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability. See “Item 1. Business — Government Regulation" on page 16 in this Form 10-K for further discussion.

Federal and state statutes require the Company to restore mine property in accordance with specified standards and an approved reclamation plan, and require that the Company obtain and periodically renew permits for mining operations. Regulations require the Company to incur the cost of reclaiming current mine disturbance at operations where the Company holds the mining permit. Estimates of the Company's total reclamation and mine closing liabilities are based upon permit requirements and the Company's engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on the Company’s business and could significantly reduce its profitability.

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA, ACE and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or ACE emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions on a number of these compounds, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. A reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations. See “Item 1. Business — Government Regulation" on page 16 in this Form 10-K for further discussion.

Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.

Many conditions beyond the Company's control can decrease the delivery, and therefore the use, of coal to the Company's customers. These conditions include weather, pandemics, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, which could significantly reduce the Company's profitability.

The Company estimates recoverable coal reserves based on engineering and geological data assembled and analyzed by internal and, less frequently, external engineers and geologists. The Company's estimates as to the quantity and quality of the coal in its reserves are updated annually to reflect production of coal from the reserves and new drilling, engineering or other data. These estimates depend upon a variety of factors and assumptions, many of which involve uncertainties and factors beyond the Company's control, such as geological and mining conditions that may not be fully identified by available exploration data or that may differ from experience in current operations.

For these reasons, estimates of the recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves may vary substantially. In addition, coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to the Company's reserves may vary materially from estimates. Accordingly, the Company's estimates may vary from

the actual reserves. Any inaccuracy in the reserve estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.

The Company conducts a significant part of its coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. The Company may not verify title to leased properties or associated coal reserves until the Company has committed to developing those properties or coal reserves. The Company may not commit to develop property or coal reserves until the Company has obtained necessary permits and completed exploration. As such, the title to property that the Company intends to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, some leases require the Company to produce a minimum quantity of coal and/or pay minimum production royalties. The Company's inability to satisfy those requirements may cause the leasehold interest to terminate.

The Company has expanded its overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as the Company scales the NAMining business, including growth outside of Florida and providing general and administrative resources to support NAMining’s growth. As NACCO continues to grow the NAMining business, the Company must effectively integrate, develop and motivate new employees, as well as existing employees who are promoted or moved into new roles, while maintaining the effectiveness of its business execution. In part, NAMining’s success depends on its ability to integrate new customers in an efficient and effective manner. The Company anticipates that it will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If the Company is unable to manage this growth effectively, the Company may not be able to take advantage of market opportunities. The Company may also fail to execute on its business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.

From time to time, the Company seeks to develop new mining projects, including the Thacker Pass project. The costs and risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on the Company’s business, financial condition and results of operations.

NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that its existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.

The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. In recent years, a significant portion of the Minerals Management segment's income has been derived from lease signing bonus and production payments associated with

assets in the Utica Shale in Ohio. During 2020, the Company acquired additional mineral interests in the Permian Basin in Texas. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company’s mineral acreage in Ohio and Texas. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions relating to the hydraulic fracturing process are adopted in areas where the Company owns mineral and royalty interests, the Company’s lessees’ may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments gives the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

The majority of the Company's producing mineral and royalty interests are located predominantly in the Utica Shale Basin in Ohio and the Permian Basin in Texas. As a result of this concentration, the Company may be disproportionately exposed to the impact of regional supply and demand factors, pricing differentials, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. This concentration could result in a relatively greater impact on results of operations than on other companies that have a more diversified portfolio of mineral and royalty interests. Such impacts could have a material adverse effect on the Company’s expected royalty income and the Company’s profitability.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless the Company’s third-party lessees conduct successful ongoing well development activities or the Company continually acquires mineral and royalty interests, the Company’s mineral and royalty interests will decline as those reserves are produced. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators’ success in developing the Company’s current and future mineral and royalty interests. The Company may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve the Company uses to project future royalty income is subject to numerous assumptions and limitations. Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

The Minerals Management segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control; market expectations about future prices of oil and natural gas; the level of oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and

The Company’s Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated by the Company without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.

Repurchases under the stock repurchase program could affect the price of the Company's Class A common stock. The existence of a stock repurchase program could cause the price of the Company's Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for the Company’s Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of the Company’s Class A common stock may decline below the levels at which the Company repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program’s effectiveness. Furthermore, the stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares of the Company's Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of the Company's Class A common stock to decline.

The price of the Company's common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in the Company's quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism; (v) announcements concerning NACCO or its competitors; (vi) lack of trading liquidity; and (vii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of our common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in the Company's common stock may not be able to resell their stock at or above the price they paid or at all. Further, NACCO could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on the Company's operating results.

The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions, contractual limitations and other factors the Board of Directors may consider. Accordingly, holders of NACCO's common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.

Provisions contained in the Company's certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire the Company, even if doing so might be beneficial to NACCO's stockholders. Provisions of the Company's by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of NACCO's common stock and may have the effect of delaying or preventing a change in control.

The Company is currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare the Company's performance with other public companies.

NACCO cannot predict whether investors will find our common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for the Company's common stock and the stock price may be more volatile.

The Company has two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2020, accounted for approximately 26 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2020, accounted for the remaining voting power of the Company. As of December 31, 2020, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 98 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 82 percent of the Company's total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.

The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. The Company’s wholly-owned subsidiary, NACoal, has an unsecured revolving line of credit of up to $150.0 million that expires in August 2022. The Company’s ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure. The volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to

reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or obtaining a refinancing with terms that are not as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's operating results and financial condition.

The Company holds a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because the Company is involved in the coal mining industry, costs of insurance may increase substantially or insurance carriers may decide not to insure the Company in the future. In addition, if the Company makes significant insurance claims, its ability to obtain future insurance coverage at commercially reasonable rates could be materially adversely affected. An inability to obtain insurance coverage, significant increases in the premiums or deductibles of insurance the Company obtains, or losses in excess of its liability insurance coverage limits, which may go down in the future, could have a material adverse effect on the Company's operating results and financial condition.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. The Company could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce the Company’s carbon footprint and promote sustainability. Investors may request the Company implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, the Company may face reputational challenges in the event its ESG practices are inconsistent with the third party views of acceptable ESG practices. Companies which do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

Like many other companies, the Company is the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers.

As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat the Company's or a third-party service provider's security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications the Company may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.

A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of the Company's business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and the Company's reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.

The Company relies on information technology systems to operate its business and to record and process transactions; respond to customer inquiries; purchase supplies; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite the Company's efforts, the Company’s information technology systems may be vulnerable, from time to time, to damage or interruption from computer viruses, power outages, third-party intrusions and other technical malfunctions.

Through the Company’s business operations, the Company collects and stores confidential information from its customers and vendors and personal information and other confidential information from its employees. Although the Company has taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate the Company’s or its vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact the Company’s ability to respond appropriately.

The Company could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt the Company’s operations, damage the Company’s reputation, and expose the Company to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on the Company’s business, financial condition and results of operations.

Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support the Company's activities could impact us. For example, although the Company has not experienced any material impacts from the SolarWinds Orion cybersecurity breach that was widely publicized in December 2020, similar future events could have a material impact to the Company. The Company is continuously installing new and upgrading existing information technology systems. The Company uses employee awareness training around phishing, malware, and other cyber risks. The Company believes these incidents are likely to continue and is unable to predict the direct or indirect impact of future attacks or breaches to business operations.

The Company’s results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies, such as the global outbreak of COVID-19. The COVID-19 pandemic resulted in governments around the world implementing stringent measures to help control the spread of the virus, including quarantines, "shelter in place" and "stay at home" orders, travel restrictions, business curtailments, school closures, and other measures.

Throughout the pandemic, the Company has continued to operate as an essential business because it supports critical infrastructure industries, as defined by the U.S. Department of Homeland Security. Although the Company has continued to operate facilities consistent with federal guidelines and state and local orders, the ongoing COVID-19 pandemic and the preventive or protective actions taken by governmental authorities may have a material adverse effect on the Company’s operations, work force, supply chain or customers, including business shutdowns or disruptions. The extent to which COVID-19 may adversely impact the Company's businesses depends on future developments, which are highly uncertain and unpredictable, including the extent of new outbreaks, the extent to which additional actions to mitigate the COVID-19 pandemic may be needed, the nature of government public health guidelines and the public's adherence to those guidelines, and the timing for proven treatments and availability of vaccines for COVID-19. Any resulting financial impact cannot reasonably be estimated at this time, but could have a material adverse effect on the Company’s financial condition, cash flows and results of operations.

Even after the COVID-19 pandemic has subsided, the Company may experience material adverse effects due to a decline in economic activity.

The Company’s operations are subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment. While all of the Company’s operations are located in the United States, the Company participates in a global supply chain, and if a disease spreads sufficiently to cause a pandemic (or to cause the fear of a pandemic to rise) or governments regulate or restrict the flow of labor or products or impede the travel of Company personnel, the Company’s ability to conduct normal business operations could be impacted which could adversely affect the Company’s results of operations and liquidity.

Proven and probable coal reserves and deposits are estimated at approximately 1.9 billion tons (including the Unconsolidated Subsidiaries), all of which are lignite coal deposits, except for approximately 58.0 million tons of bituminous coal. Reserves are estimates of quantities of coal, made by the Company's geological and engineering staff, which are considered mineable in the future using existing operating methods. Developed reserves are those which have been allocated to mines which are in operation; all other reserves are classified as undeveloped. Information concerning mine type, reserve data and coal quality characteristics are set forth on the table on pages 9 and 10 under “Item 1. Business — SEC Industry Guide 7 Information .”

Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

As a “smaller reporting company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, the Company is not required to provide this information.

All financial statement line items below operating profit (other income, including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See “Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

The components of the change in revenues and operating profit are discussed below in "Segment Results."

North American Coal Corporation India Private Limited ("NACC India") was formed to provide technical business advisory services to the third-party owner of a coal mine in India. During 2014, NACC India's customer defaulted on its contractual payment obligations and as a result of this default, NACC India terminated its contract with the customer and began pursuing contractual remedies. During 2019, the Company received payment of $2.7 million from NACC India's customer, of which $1.4 million related to past invoices and has been reported on the line Other, net, and $1.3 million represented interest income and has been reported on the line Interest income. During 2020, the Company received an additional payment of $1.0 million from NACC India's customer which has been reported on the line, Other, net. Both of these lines are in the Other (income) expense section of the Consolidated Statements of Operations. The Company does not expect to receive any additional payments from NACC India’s customer.

Interest expense increased $0.5 million due to higher average borrowings during 2020 compared with 2019.

Interest income decreased $2.4 million primarily due to the interest income related to the NACC India customer payment the Company received in 2019 and lower interest rates on invested cash during 2020 compared with 2019.

Income from other unconsolidated affiliates represents the financial results of NoDak. NoDak operated and maintained a coal drying system at a customer’s power plant. The NoDak contract expired on January 31, 2020, resulting in a decrease of $1.1 million in Income from other unconsolidated affiliates during 2020 compared with 2019.

Other, net, increased $0.6 million primarily due to the absence of $0.9 million in settlement expense for the Combined Defined Benefit Plan recognized during 2019. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's pension and postretirement expense.

The Company recorded an income tax benefit of $0.5 million for the year ended December 31, 2020 on income before income tax of $14.3 million, or (3.8%), compared to income tax expense of $3.8 million on income before income tax of $43.4 million, or 8.7%, for the year ended December 31, 2019. The year ended December 31, 2020 includes $7.3 million of discrete tax charges primarily related to settlement of tax examinations, reserves for uncertain tax positions and return to provision adjustments partially offset by a benefit of $4.7 million, primarily due the rate differential related to carrying back losses under the provisions of the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act"). The CARES Act allows net operating tax losses incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company generated a net tax operating loss in 2020 primarily due to the realization of certain deferred tax assets. Discrete tax items in the year ended December 31, 2019 were a benefit of $2.5 million primarily resulting from changes in prior year estimates and the effective settlement of certain discrete tax items from on-going examinations.

The Company’s effective income tax rate, excluding the CARES Act and discrete items, was (22.0%) and 14.5% for the years ended December 31, 2020 and 2019, respectively. The effective income tax rate differs from the U.S. federal statutory rate primarily due to the benefit from percentage depletion. The benefit of percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, as a result of the $29.1 million reduction in income before income tax in 2020 compared to 2019, the proportional effect of the benefit from percentage depletion on the effective income tax rate in 2020 resulted in a significantly lower effective tax rate in 2020 compared to 2019.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

The $55.3 million decrease in net cash provided by operating activities was primarily the result of unfavorable working capital changes and the decrease in net income, partially offset by impairment charges. Working capital changes primarily included:

The increase in net cash used for investing activities was primarily attributable to $14.2 million in acquisitions of mineral and royalty interests at the Minerals Management segment during 2020 compared with none during 2019.

The change in net cash provided by financing activities was primarily due to increased borrowings during 2020 compared with 2019.

Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of NACoal. The borrowing agreements at NACoal allow for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by NACoal's borrowing agreement) and management fees are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders.

The Company believes funds available from cash on hand, the NACoal Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the NACoal Facility.

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2020, for base rate and LIBOR loans were 0.75% and 1.75%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.30% on the unused commitment at December 31, 2020. The weighted average interest rate applicable to the NACoal Facility at December 31, 2020 was 1.88% including the floating rate margin.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum debt to EBITDA ratio of 3.00 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 2.00 to 1.00, or if greater than 2.00 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2020, NACoal was in compliance with all financial covenants in the NACoal Facility.

NACoal’s variable interest payments are calculated based upon NACoal’s anticipated payment schedule and the December 31, 2020 base rate and applicable margins, as defined in the NACoal Facility. A 1/8% increase in the base rate would increase NACoal’s estimated total annual interest payments on the NACoal Facility by less than $0.1 million.

Following is a table which summarizes actual and planned expenditures (in millions):

Planned expenditures for 2021 are expected to be approximately $46 million, primarily consisting of $27 million in the Coal Mining segment, $10 million in the Minerals Management segment and $9 million in the NAMining segment.

In the Coal Mining segment, elevated levels of expected capital expenditures through 2021 are primarily related to spending at MLMC as it develops a new mine area. In the Minerals Management segment, expected expenditures in 2021 are primarily for the acquisition of mineral interests. In the NAMining segment, expected capital expenditures in 2021 are primarily for the acquisition, relocation and refurbishment of draglines.

Expenditures are expected to be funded from internally generated funds and/or bank borrowings.

NACCO's consolidated capital structure is presented below:

The increase in other net tangible assets was primarily due to increases in Property, plant and equipment as well as payments made for deferred compensation and accrued incentive compensation during 2020.

Revenues increased 4.9% in 2020 compared with 2019 primarily due to an increase in price per ton attributable to reimbursable costs at MLMC. The sales price at MLMC is index-based and includes adjustments for coal quality and reimbursable costs.

Also contributing to the increase is reclamation revenue from Caddo Creek. On September 30, 2020, Caddo Creek's customer, a division of Cabot Corporation, entered into a long-term supply agreement with a subsidiary of Advanced Emissions Solutions (“AES”) as well as an agreement for the sale of the Marshall Mine, operated by Caddo Creek, to a subsidiary of

AES. AES announced its intent to close the Marshall Mine. Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation. As a result of these changes, Caddo Creek financial results are now consolidated within the Coal Mining segment.

The following table identifies the components of change in operating profit for 2020 compared with 2019:

Operating profit decreased $8.7 million in 2020 compared with 2019. The change in operating profit was primarily due to:

Revenues decreased 1.0% in 2020 compared with 2019, primarily due to lower reimbursed costs, which have an offsetting amount in cost of goods sold and have no impact on operating profit. The decrease was partially offset by favorable changes in the mix of customer requirements and work related to the Thacker Pass lithium project.

The following table identifies the components of change in operating profit (loss) for 2020 compared with 2019.

NAMining reported operating profit of $1.9 million in 2020 compared with an operating loss of $0.6 million in 2019. The change is primarily due to an increase in gross profit and in earnings of unconsolidated operations. Both variances are due to changes in the mix of customer requirements.

The $3.1 million decrease in operating loss during 2020 compared with 2019 was primarily due to lower employee-related expenses.

During the fourth quarter of 2020, the Company implemented a voluntary separation program for employees who met certain age and service requirements to reduce overall headcount. As a result of this program, the 2020 operating loss includes a charge of $0.3 million related to one-time termination benefits.

In 2021, the Company expects coal deliveries to be comparable to 2020 based on current expectations of customer requirements.

Coal Mining operating profit in 2021 is expected to decrease significantly from 2020. This decrease is primarily attributable to substantially lower earnings expected at MLMC and reduced earnings at the unconsolidated Coal Mining operations. MLMC

earnings are expected to be lower as a result of an anticipated increase in the cost per ton of coal delivered in 2021 compared with 2020, due in part to an increase in depreciation expense associated with development of a new mine area. The anticipated reduction in earnings at the unconsolidated Coal Mining operations is expected to be mainly driven by a reduction in fee-based earnings at the Liberty Mine, as the scope of final mine reclamation activities is reduced. Lower operating profit is expected to be partially offset by a decrease in operating expenses primarily due to lower employee-related costs resulting from the 2020 voluntary separation program partially offset by higher insurance expense.