EDGAR 10-K Filing

Company CIK: 789933
Filing Year: 2021
Filename: 789933_10-K_2021_0000789933-21-000011.json

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ITEM 1. BUSINESS
Item 1. BUSINESS
General
NACCO Industries, Inc.® (“NACCO” or the “Company”), through a portfolio of mining and natural resources businesses, operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The Minerals Management segment acquires and promotes the development of oil, gas and coal mineral interests, generating income primarily from royalty-based lease payments from third parties. In addition, the Company has a business providing stream and wetland mitigation solutions.
The Company has items not directly attributable to a reportable segment which are not included as part of the measurement of segment operating profit, which are primarily administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources of North America® (“MRNA”) and Bellaire Corporation (“Bellaire”). MRNA generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.
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.
Business Strategy
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.
Business Developments
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.
Coal Mining Segment
The Coal Mining segment, operating as North American Coal Corporation® ("NACoal"), operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface-mined in North Dakota, Texas, Mississippi, Louisiana and on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.
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.
NAMining Segment
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.
Minerals Management Segment
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.
During 2020, the Minerals Management segment acquired mineral interests in the Permian Basin in Texas and intends to make future acquisitions of mineral and royalty interests that meet the Company’s acquisition criteria as part of its growth strategy. The acquisition criteria includes building a blended portfolio of mineral and royalty interests (i) with new wells anticipated to come online within one to two years of investment, (ii) in areas with forecasted future development within five years after acquisition, or (iii) with existing producing wells further along the decline curve that will generate stable cash flow. In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian and Williston basins and a secondary focus on other diversifying basins to increase regional exposure. While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in overriding royalty interests, non-participating royalty interests or non-operated working interests under certain circumstances. The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator.
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.
•Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. Holders of royalty interests are generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have no environmental liability. Royalty interests expire upon the expiration of the oil and gas lease.
•Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine, and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.
•Non-Participating Royalty Interest (“NPRIs”). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases.
•Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.
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 Net
Oil 279 0.2
Natural Gas 408 26.5
Total 687 26.7
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.
Customers
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:
Percentage of Consolidated Revenue
Segment 2020 2019
Coal Mining customer 55 % 48 %
NAMining customer 19 % 21 %
Minerals Management lessee less than 10% 12 %
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.
Competition
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.
Seasonality
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.
Human Capital
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.
Available Information
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.
SEC Industry Guide 7 Information
The following map shows the Coal Mining segment's locations:
The location, mine type, reserve data, coal quality characteristics, sales tonnage and contract expiration date for the Coal Mining segment were as follows:
COAL MINING OPERATIONS ON AN “AS RECEIVED” BASIS
2020 2019
Proven and Probable Reserves (a)(b)
Committed
Under
Contract Uncommitted Total Tons
Delivered
(Millions) Owned
Reserves
(%) Leased
Reserves
(%) Total
Committed
and
Uncommitted
(Millions of
Tons) Tons
Delivered
(Millions) Contract
Expires
Mine/Reserve Type of Mine (Millions of Tons)
Unconsolidated Mines
Freedom Mine (c)-
The Coteau Properties Company Surface Lignite 438.0 - 438.0 12.6 3 % 97 % 432.8 13.5 2022 (d)
Falkirk Mine (c)(e)-
The Falkirk Mining Company Surface Lignite 12.0 358.6 370.6 7.2 1 % 99 % 375.7 7.4 2045 (e)
South Hallsville No. 1 Mine (c)(f)(g)-
The Sabine Mining Company Surface Lignite 3.4 97.3 100.7 1.9 (f)(g) (f)(g) 102.6 2.6 2035 (g)
Five Forks Mine (c)(f)-
Demery Resources Company, LLC Surface Lignite 4.9 - 4.9 0.2 (f) (f) 4.9 0.1 2030
Marshall Mine (c)(f)(h)-
Caddo Creek Resources Company, LLC Surface Lignite (h) (h) (h) 0.1 (f)(h) (f)(h) 19.2 0.2 (h)
Eagle Pass Mine (c)(f)(i)-
Camino Real Fuels, LLC Surface
Bituminous (i) (i) (i) 0.3 (f)(i) (f)(i) 15.6 1.5 (i)
Coyote Creek Mine (c)-
Coyote Creek Mining Company, LLC Surface Lignite 72.4 - 72.4 2.0 0 % 100 % 69.6 1.7 2040
Navajo Mine (c)(j)- Bisti Fuels Company Surface
Sub-bituminous (j) (j) (j) 4.2 (j) (j) (j) 5.0 2031
Consolidated Mines
Red Hills Mine-
Mississippi Lignite Mining Company Surface Lignite 161.0 76.3 237.3 2.5 44 % 56 % 240.0 2.6 2032
Centennial Natural Resources Surface Bituminous 17.0 - 17.0 - 40 % 60 % 43.0 - (k)
Total Developed 708.7 532.2 1,240.9 31.0 1,303.4 34.6
Undeveloped Mines
North Dakota - 221.4 221.4 - 100 % 243.9 -
Texas - 210.3 210.3 - 100 % 222.5 -
Eastern (l) - 41.0 41.0 - 100 % 41.0 -
Mississippi - 188.2 188.2 - 100 % 188.2 -
Total Undeveloped - 660.9 660.9 - 695.6 -
Total Developed/Undeveloped 708.7 1,193.1 1,901.8 1,999.0
Average Coal Quality (As received)
Mine/Reserve Type of Mine Coal Formation or
Coal Seam(s) Average Seam
Thickness (feet) Average
Depth (feet) BTUs/lb Sulfur
(%) Ash
(%) Moisture (%)
Unconsolidated Mines
Freedom Mine (c)-
The Coteau Properties Company Surface Lignite Beulah-Zap Seam 16 100 6,700 0.90 % 9 % 36 %
Falkirk Mine (c)-
The Falkirk Mining Company Surface Lignite Hagel A&B, Tavis
Creek, Kinneman Creek Seams 8 115 6,200 0.62 % 11 % 38 %
South Hallsville No. 1 Mine (c)(f)-
The Sabine Mining Company Surface Lignite Wilcox Formation 3 85 6,448 0.79 % 18.2 % 32 %
Five Forks Mine (c)(f)-
Demery Resources Company, LLC Surface Lignite Wilcox Formation I Seam 4.4 44 7,033 0.44 % 7.8 % 37 %
Marshall Mine (c)(f)(h)-
Caddo Creek Resources Company, LLC Surface Lignite (h) (h) (h) (h) (h) (h) (h)
Eagle Pass Mine (c)(f)(i)-
Camino Real Fuels, LLC Surface Bituminous (i) (i) (i) (i) (i) (i) (i)
Coyote Creek Mine (c)-
Coyote Creek Mining Company, LLC Surface Lignite Beulah-Zap Seam 10 95 6,900 0.93 % 9 % 35 %
Navajo Mine (c)(j)- Bisti Fuels Company Surface
Sub-bituminous (j) (j) (j) (j) (j) (j) (j)
Consolidated Mines
Red Hills Mine-
Mississippi Lignite Mining Company Surface Lignite C, D, E, F, G, H Seams 3.4 150 5,100 0.60 % 15 % 43 %
Centennial Natural Resources Surface Bituminous Black Creek, New Castle, Mary Lee, Jefferson, American, Nickel Plate, Pratt Seams 1.75 178 13,226 2.00 % 10 % 4 %
Undeveloped Mines
North Dakota - Fort Union Formation 13 130 6,500 0.8 % 8 % 38 %
Texas - Wilcox Formation 5 120 6,800 1.0 % 16 % 30 %
Eastern - Freeport & Kittanning Seams 4 400 12,070 3.3 % 12 % 3 %
Mississippi - Wilcox Formation 5 130 5,200 0.6 % 13 % 44 %
(a)Committed and uncommitted tons represent in-place estimates. The projected extraction loss is approximately 10% of the proven and probable reserves, except with respect to the Eastern Undeveloped Mines, in which case the projected extraction loss is approximately 50% of the proven and probable reserves.
(b)The Company's reserve estimates are generally based on the entire drill hole database for each reserve, which was used to develop a geologic computer model using triangulation methods and inverse distance to the second power as an interpolator for NACCO's reserves. As such, all reserves are considered proven (measured) within the Company's reserve estimate. None of the Company's coal reserves have been reviewed by independent experts. The Company’s estimate of the economic viability of the proven and probable reserve estimates for tons committed to customers pursuant to long-term contracts are supported by existing long-term contracts to mine coal on behalf of customers and life-of-mine plans associated with those contracts. The contracts with each customer of the Unconsolidated Mines eliminate Company exposure to spot coal market price fluctuations. At the Unconsolidated Mines, compensation from each customer to the Company includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. Red Hills Mine - 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. MLMC is the exclusive supplier of coal to its customer’s power plant under its contract that runs through 2032. The Company’s assessment of the economic viability of the mineral reserves associated with MLMC takes into account estimated customer demand, including the minimum annual take provision in the contract, as well as cost of production. The economic viability of the uncommitted reserves assumes coal would be mined in a mine-mouth operation that minimizes or eliminates transportation costs and under contract terms, which are similar to those contained in the Company’s existing long-term management fee contracts, or leased to other miners. The majority of the Company’s uncommitted reserves are located in close proximity to power generation or other facilities, which could allow a mine-mouth operation. Lessees of this coal generally would mine the coal if the coal sale price would exceed the lessee operating costs. As to coal mined and sold by lessees, the Company would receive a royalty based on a percentage of the sale price. See footnote (h) for coal reserves currently leased to others.
(c)The contracts for these mines require the customer to cover the cost of the ongoing replacement and upkeep of the plant and equipment of the mine.
(d)Although the term of the existing coal sales agreement terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of the Company.
(e)On May 7, 2020, 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.
(f)These reserves are owned or controlled by customers. The Company conducts activities to extract these customer-owned and controlled reserves pursuant to long-term service contracts.
(g)On November 5, 2020, AEP, Sabine Mine's customer, announced its intent to retire the Pirkey Plant in 2023 in order to comply with the U.S. Environmental Protection Agency’s Coal Combustion Residuals rule.
(h)On September 30, 2020, a division of Cabot Corporation, Marshall Mine's customer, entered into an agreement for the sale of the Marshall Mine 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.
(i)The contract mining agreement between Camino Real and its customer, DRCP, terminated effective July 1, 2020 and resulted in the closure of Camino Real's Eagle Pass Mine.
(j)These reserves are owned or controlled by Bisti's customer and it controls proven and probable reserve data. Bisti’s customer declined to allow us to include the proven and probable reserve data in this Form 10-K. The Company conducts activities to extract these customer-owned and controlled reserves pursuant to a long-term service contract.
(k)Centennial ceased active mining operations at the end of 2015.
(l)The proven and probable reserves included in the table do not include coal that is leased to others. The Company had 69.0 million tons and 70.0 million tons in 2020 and 2019, respectively, of Eastern Undeveloped Mines with leased coal committed under contract.
Unconsolidated Mines
Freedom Mine - The Coteau Properties Company
The Freedom Mine generally produces between 12.5 million and 13.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. 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.
The Freedom Mine, operated by Coteau, is located approximately 90 miles northwest of Bismarck, North Dakota. The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 381 leases granting the right to mine approximately 34,715 acres of coal interests and the right to utilize approximately 23,575 acres of surface interests. In addition, Coteau owns in fee 33,525 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.
The reserves are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom 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.
Falkirk Mine - The Falkirk Mining Company
The Falkirk Mine started delivering coal in 1978 primarily for the Coal Creek Station, an electric power generating station owned by GRE. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.
On May 7, 2020, GRE 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. The Falkirk Mine delivered 7.2 million and 7.4 million tons of lignite coal, primarily for the Coal Creek Station, during 2020 and 2019, respectively. The terms of the contract between the Company and GRE specify that GRE is responsible for all costs related to mine closure, including but not limited to, final mine reclamation costs, post-retirement medical benefits and pension costs with respect to Falkirk employees.
The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83. Falkirk holds 311 leases granting the right to mine approximately 43,084 acres of coal interests and the right to utilize approximately 24,061 acres of surface interests. In addition, Falkirk owns in fee 41,275 acres of surface interests and 1,789 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.
The reserves are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coals in the reserve occur in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.
South Hallsville No. 1 Mine - The Sabine Mining Company
The South Hallsville No. 1 Mine started delivering coal in 1985. All production from the mine 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 South Hallsville No. 1 Mine delivered 1.9 million and 2.6 million tons to the Pirkey Plant in 2020 and 2019, respectively. During the third quarter of 2020, SWEPCO reduced its expected future annual delivery requirements to be between 1.4 million and 1.7 million tons. The terms of the contract between the Company and SWEPCO specify that SWEPCO is responsible for all costs related to mine closure, including but not limited to, final mine reclamation costs, post-retirement medical benefits and pension costs with respect to Sabine employees.
The South Hallsville No. 1 Mine, operated by Sabine, is located approximately 150 miles east of Dallas, Texas on FM 968. The entrance to the mine is by means of a paved road. Sabine has no title, claim, lease or option to acquire any of the reserves at the South Hallsville No. 1 Mine. Southwestern Electric Power Company controls all of the reserves within the South Hallsville No. 1 Mine.
Five Forks Mine - Demery Resources Company, LLC
The Five Forks Mine, operated by Demery, began delivering coal in 2012 and is located approximately three miles north of Creston, Louisiana on State Highway 153. Access to the Five Forks Mine is by means of a paved road. Demery has no title, claim, lease or option to acquire any of the reserves at the Five Forks Mine. Demery's customer, Five Forks Mining, LLC, controls all of the reserves within the Five Forks Mine.
Marshall Mine - Caddo Creek Resources Company, LLC
On September 30, 2020, Caddo Creek's customer, a division of Cabot Corporation, entered into a long-term supply agreement with a subsidiary of AES as well as an agreement for the sale of the Marshall Mine 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.
Eagle Pass Mine - Camino Real Fuels, LLC
The Eagle Pass Mine, operated by Camino Real, began delivering coal in 2015 to Camino Real's customer, Dos Republicas Coal Partnership ("DRCP"). The contract mining agreement between Camino Real and 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.
Coyote Creek Mine - Coyote Creek Mining Company, LLC
In 2016, the Coyote Creek Mine began delivering coal to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. The Coyote Creek Mine generally produces approximately 1.5 million to 2.5 million tons of lignite coal annually when Coyote Station is operating at anticipated levels.
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.
Navajo Mine - Bisti Fuels Company, LLC
Bisti has been the contract miner at Navajo Transitional Energy Company's ("NTEC's") Navajo Mine since 2017. Bisti generally delivers approximately 5.0 million tons of sub-bituminus coal to the Four Corners Power Plant when the plant is operating at anticipated levels.
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.
Consolidated Mines
Red Hills Mine - Mississippi Lignite Mining Company
The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant.
The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 7,061 acres of surface interest and 4,162 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,953 acres of coal interests and the right to utilize approximately 5,850 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,541 acres of coal interests. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations.
The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.
Centennial Natural Resources
Centennial ceased active mining operations at the end of 2015. Centennial and its affiliate, North American Coal Royalty Company, own in fee approximately 5,602 acres of coal interests and approximately 2,323 acres of surface interests in Alabama. Centennial holds leases in Alabama granting the right to mine approximately 3,907 acres of coal interests and the right to utilize approximately 4,698 acres of surface interests. The majority of the leases held by Centennial were originally acquired between 2000 and 2012 with terms that can be extended by the continuation of mining activities.
North American Mining
NAMining primarily operates and maintains draglines to mine limestone and sand at the following mines in Florida and Virginia pursuant to mining services agreements with the mine owners:
Location Name Location Customer Year NACCO Started Operations
White Rock - North Miami WRQ 1995
Krome Miami Cemex 2003
Alico Ft. Myers Cemex 2004
FEC Miami Cemex 2005
SCL Miami Cemex 2006
Card Sound Florida City Cemex 2009
Central State Aggregates Zephyrhills McDonald Group 2016
Mid Coast Aggregates Sumter County McDonald Group 2016
West Florida Aggregates Hernando County McDonald Group 2016
St. Catherine Sumter County Cemex 2016
Center Hill Sumter County Cemex 2016
Inglis Crystal River Cemex 2016
Titan Corkscrew Ft. Myers Titan America 2017
Palm Beach Aggregates Loxahatchee Palm Beach Aggregates 2017
Perry Lamont Martin Marietta 2018
SDI Aggregates Florida City Blue Water Industries 2018
Queensfield King William County, VA King William Sand and Gravel Company, Inc. 2018
County Line Pasco County K&M Pasco 130 Holdings, LLC 2019
Newberry Alachua County Argos USA, LLC 2019
Titan Pennsuco Miami Titan America 2020
NAMining's customers control all of the limestone and sand reserves within their respective mines.
Access to the White Rock mine is by means of a paved road from 122nd Avenue.
Access to the Krome mine is by means of a paved road from Krome Avenue.
Access to the Alico mine is by means of a paved road from Alico Road.
Access to the FEC mine is by means of a paved road from NW 118th Avenue.
Access to the SCL mine is by means of a paved road from NW 137th Avenue.
Access to the Card Sound mine is by means of a paved road from SW 408th Street.
Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.
Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.
Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.
Access to the St. Catherine mine is by means of a paved road from County Road 673.
Access to the Center Hill mine is by means of a paved road from West Kings Highway.
Access to the Inglis mine is by means of a paved road from Highway 19 South.
Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.
Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.
Access to the Perry mine is by means of paved road from Nutall Rise Road.
Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.
Access to the Queensfield Mine is by means of paved road from Dabney's Mill Road (SR 604).
Access to the County Line mine is by means of paved road from 18744 County Line Road.
Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).
Access to the Titan Pennsuco mine is by means of a paved road from NW 121st Way.
NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.
General Information
Leases. The leases held by Coteau, Coyote Creek, Falkirk and MLMC have a variety of continuation provisions, but generally permit the leases to be continued beyond their fixed terms. Centennial holds the mining rights to certain of its reserves through fee ownership, and leases and licenses from the coal and surface owners. NACCO expects coal will be available to meet customers' future production requirements utilizing land and reserves that are currently owned or leased or accessible through ownership acquisition or new leases.
Previous Operators. There were no previous operators of the Freedom Mine, Falkirk Mine, South Hallsville No. 1 Mine, Five Forks Mine, Marshall Mine, Eagle Pass Mine, Coyote Creek Mine or Red Hills Mine. NTEC's Navajo Mine was previously operated by a third party.
Exploration and Development. All coal mines are well past the exploration stage. Additional pit development is under way at each operating mine. Drilling programs are routinely conducted for the purpose of refining guidance related to ongoing operations. For example, at the Red Hills Mine, the lignite coal reserve has been defined by a drilling program that is designed to provide 500-foot spaced drill holes for areas anticipated to be mined within four years of the current pit. Drilling beyond the four-year horizon ranges from 1,000 to 2,000-foot centers. Drilling is conducted annually to stay current with the advance of mining operations. Geological evaluation is in process at all operating locations.
Facilities and Equipment. The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what
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:
Location Mining Method Total Historical Cost of Mine
Property, Plant and Equipment
(excluding Coal Land, Real Estate
and Construction in Progress), Net of
Applicable Accumulated
Amortization, Depreciation and Impairment
(in millions)
Unconsolidated Mining Operations
Freedom Mine - The Coteau Properties Company Dragline operation with 3 draglines $ 81.5
Falkirk Mine - The Falkirk Mining Company Dragline operation with 4 draglines $ 157.6
South Hallsville No. 1 Mine - The Sabine Mining Company Dragline operation with 4 draglines $ 110.5
Five Forks Mine - Demery Resources Company, LLC Truck-shovel operation $ -
Coyote Creek Mine - Coyote Creek Mining Company, LLC Dragline operation with 1 dragline $ 140.9
Navajo Mine - Bisti Fuels Company, LLC Dragline operation with 2 draglines $ -
Consolidated Mining Operations
Red Hills Mine - Mississippi Lignite Mining Company Dragline operation with 1 dragline $ 63.6
Marshall Mine - Caddo Creek Resources Company, LLC N/A $ -
Eagle Pass Mine - Camino Real Fuels, LLC N/A $ -
NAMining (a) $ 12.0
Other N/A $ 1.2
(a) During 2020, NAMining operated 32 draglines and one rope shovel at 20 quarries. Of the 32 draglines, 8 are owned by the Company and 24 are owned by customers. The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer.
Predominantly all of Bisti and Demery's machinery and equipment is owned by the customer of the respective mines.
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.
Government Regulation
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.
Numerous governmental permits and approvals are required for coal mining operations. The Company's subsidiaries hold or will hold the necessary permits at all of its coal mining operations except Demery, Caddo Creek, Bisti and Camino Real, where the customers hold, or held, the respective permits. The Company believes, based upon present information provided to it by these third-party mine permit holders, that these third parties have all permits necessary for the Company to operate or reclaim Caddo Creek, Demery and Bisti; however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.
At the coal mining operations where the Company's subsidiaries hold the permits, the Company is required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.
Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.
Mine Health and Safety Laws
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.
Environmental Laws
The Company's coal mining operations are subject to various federal environmental laws, as amended, including:
•the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”);
•the Clean Air Act, including amendments to that act in 1990 (“CAA”);
•the Clean Water Act of 1972 (“CWA”);
•the Resource Conservation and Recovery Act ("RCRA"); and
•the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").
In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations. Both federal and state inspectors regularly visit mines to enforce compliance. The Company has ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. 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 Coal Mining segment.
Surface Mining Control and Reclamation Act
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.
Clean Air Act and Affordable Clean Energy Rule ("ACE")
The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA 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 emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of 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 in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing 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.
States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone, and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years. In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In November 2020, EPA published a proposed “Revised Cross-State Air Pollution Rule” to address the remand of the CSAPR update. If promulgated as drafted, this proposed rule will require no further obligations in states where the Company’s customers operate a power plant.
The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.
The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze
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.
Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.
The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.
Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.
The U.S. Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and “cap-and-trade” programs, and mandates or incentives to generate electricity by using renewable resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.
The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, the ACE rule limited "best system of emission reduction" ("BSER") to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and vacated the ACE rule. It is anticipated that the Biden administration will draft a new rule to regulate CO2 emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company’s business, financial condition or results of operations. In addition, in early 2021, the EPA issued an endangerment/significant contribution finding for CO2 emissions from coal-fired power plants. This endangerment/significant contribution finding is likely to be challenged in the DC Circuit; the outcome of the legal challenge 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.
As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change (“Paris Agreement”). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories. Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets. The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a materially adverse effect on the Company’s business, financial condition and results of operations.
Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.
The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.
Clean Water Act
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.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In December 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule. One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. This new rule may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal.
The EPA rule exempts CCRs disposed of at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.
Regulation of the Oil and Natural Gas Industry
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.
Environmental Matters
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.
Drilling and Production
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:
•the location of wells;
•the method of drilling and casing wells;
•the timing of construction or drilling activities, including seasonal wildlife closures;
•the rates of production or "allowables";
•the surface use and restoration of properties upon which wells are drilled;
•the plugging and abandoning of wells; and
•notice to, and consultation with, surface owners and other third parties.
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.
Regulation of Hydraulic Fracturing
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.
Endangered Species Act
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.
Natural Gas Sales and Transportation
Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which our operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on our natural gas-related activities.
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.
Oil Sales and Transportation
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, the Company believes that the regulation of oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, the Company believes that access to oil pipeline transportation services generally will be available to its operators to the same extent as to the Company or its competitors.
State Regulation
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but the Company cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.
Comprehensive Environmental Response, Compensation and Liability Act
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.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2021 the name, age, current position and principal occupation and employment during the past five years of the Company’s executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected. Certain executive officers of the Company listed below are also executive officers for NACoal.
EXECUTIVE OFFICERS OF THE COMPANY
Name Age Current Position Other Positions
J.C. Butler, Jr. 60 President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from prior to 2016) From prior to 2016 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO. From prior to 2016 to September 2017, Assistant Secretary of Hamilton Beach Brands ("HBB") and Kitchen Collection ("KC").
Matthew J. Dilluvio 31 Associate Counsel and Assistant Secretary of NACCO and NACoal (from June 2019) From October 2016 to May 2019, Associate, Sidley Austin LLP (law firm). From prior to 2016 to September
2016, Associate, White and Case LLP (law firm).
Elizabeth I. Loveman 51 Vice President and Controller and Principal Financial Officer (from prior to 2016)
John D. Neumann 45 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2016) From prior to 2016 to September 2017, Assistant Secretary of HBB and KC.
Miles B. Haberer 54 Associate General Counsel of NACCO (from prior to 2016), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2016) and President, North American Coal Royalty Company (an NACoal subsidiary) (from prior to 2016)
Sarah E. Fry 45 Associate General Counsel and Assistant Secretary of NACCO (from May 2017), Associate General Counsel and Assistant Secretary of NACoal (from May 2017) From prior to 2016 to April 2017, Senior Counsel, Locke Lord (law firm).
Thomas A. Maxwell 43 Vice President - Financial Planning and Analysis and
Treasurer (from September 2017)
From prior to 2016 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.
PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES
Name Age Current Position Other Positions
Eric S. Anderson 45 President - MRNA (from March 2017) From prior to 2016 to February 2017, Environmental Manager, The Sabine Mining Company (an NACoal subsidiary)
Philip N. Berry 53 President - NAMining (from prior to 2016)
Eric A. Dale 46 Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017) From prior to 2016 to November 2016, Vice President of Financial Planning and Analysis at Westmoreland Coal Company.
Carroll L. Dewing 64 Vice President - Operations of NACoal (from January 2017) From prior to 2016 to December 2016, President, The Coteau Properties Company (an NACoal subsidiary).
From prior to 2016 to December 2016, Vice President - North Dakota, Texas and Florida Operations, Human Resources and External Affairs of NACoal.
Andrew B. Hart 42 Controller of NACoal (from September 2019) From November 2017 to August 2019, Assistant Controller of NACoal. From prior to 2016 to October 2017, Assistant Controller at Rowan Companies, plc.
Brian M. Larson 37 President - Catapult Mineral Partners, LLC (from May 2019) and Director - Oil and Gas Development (from April 2019) From prior to 2016 to March 2019, Engineer at Pioneer Natural Resources
J. Patrick Sullivan, Jr.
62 Vice President and Chief Financial Officer of NACoal (from prior to 2016)

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ITEM 1A. RISK FACTORS
Item 1A. RISK FACTORS
Risks related to the Coal Mining segment
Termination of or default under long-term mining contracts could materially reduce the Company's profitability.
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.
The loss of, or significant reduction in, purchases by our coal customers could adversely affect our business, financial condition, results of operation 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.
Mississippi Lignite Mining Company ("MLMC") is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal fired generation, changes in customer demand and inflationary adjustments.
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 Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.
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.
Changes in coal consumption patterns of U.S. electric power generators could adversely affect 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.
Government regulations could impose costly requirements on the Company and its customers.
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.
The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.
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 Clean Air Act ("CAA") and the Affordable Clean Energy ("ACE") Rule could reduce the demand for coal.
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.
The Coal Mining segment's customers' operations require significant capital expenditures.
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.
Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.
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.
Estimates of the Company's recoverable coal reserves involve uncertainties, and inaccuracies in these estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.
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.
A defect in title or the loss of a leasehold interest in certain property could limit the Company's ability to mine coal reserves or result in significant unanticipated costs.
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.
Risks related to the NAMining segment
The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.
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.
The Company is subject to the high costs and risks involved in the development of new mining projects.
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 aggregates producers that choose to self-perform mining operations and from other mining companies.
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.
Risks related to the Minerals Management segment
The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.
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 Company’s producing mineral and royalty interests are located predominantly in the Utica Shale Basin in Ohio and the Permian Basin in Texas, making the Company vulnerable to risks associated with operating in limited geographic areas.
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.
Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company’s reserves and royalty income will decline.
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.
Substantially all of the Minerals Management segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying the Company’s interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company’s control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
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
natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
Risks related to corporate structure
The Company’s stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.
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 NACCO's securities may be volatile.
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 amount and frequency of dividend payments made on NACCO's common stock could change.
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.
NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
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.
NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.
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.
Certain members of the Company's extended founding family own a substantial amount of its Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.
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.
General Risk Factors
The Company’s effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.
The Company is subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in the Company’s effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.
Current and future capital and credit market conditions could adversely affect the Company’s ability to obtain bank financing on reasonable terms.
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.
Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken action to limit coverage for companies in the coal mining industry, which could result in significant increases in costs of insurance or in the Company’s ability to maintain insurance coverage at current levels.
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.
Increasing scrutiny and changing expectations with respect to the Company’s environmental, social and governance practices may impose additional costs on the Company or expose the Company to new or additional risks.
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.
The Company’s business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.
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 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 could be disrupted by natural or human causes beyond its control.
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
Item 2. PROPERTIES
NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.
NACoal leases its corporate headquarters office space in Plano, Texas.
NAMining leases office and warehouse space in Medley, Florida.
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 .”

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ITEM 3. LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. MINE SAFETY DISCLOSURES
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.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.
At December 31, 2020, there were 705 Class A common stockholders of record and 132 Class B common stockholders of record.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Issuer Purchases of Equity Securities (1)
Period (a)
Total Number of Shares Purchased (b)
Average Price Paid per Share (c)
Total Number of Shares Purchased as Part of the Publicly Announced Program (d)
Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program (1)
October 1 to 31, 2020 - $ - - $ 22,659,516
November 1 to 30, 2020 - $ - - $ 22,659,516
December 1 to 31, 2020 - $ - - $ 22,659,516
Total
- $ - - $ 22,659,516
(1) On November 6, 2019, the Company's Board of Directors approved a stock purchase program ("2019 Stock Repurchase Program") providing for the purchase of up to $25.0 million of the Company’s outstanding Class A common stock through December 31, 2021. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. SELECTED FINANCIAL DATA
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.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
OVERVIEW
Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."
Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (“NACCO” or the “Company”). NACCO, through a portfolio of mining and natural resources businesses, operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The Minerals Management segment acquires and promotes the development of oil, gas and coal mineral interests, generating income primarily from royalty-based lease payments from third parties. In addition, the Company has a business providing stream and wetland mitigation solutions.
The Company has items not directly attributable to a reportable segment which are not included as part of the measurement of segment operating profit, which are primarily administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources of North America® (“MRNA”) and Bellaire Corporation (“Bellaire”). MRNA generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.
As of January 1, 2020, the Company retrospectively changed its computation of segment operating profit to reclassify certain expenses, primarily related to executive and board compensation. These expenses are now included in unallocated items. The change in segment reporting reflected a decision to evaluate the financial performance of the Company’s segments excluding executive and board compensation. All prior period segment information has been reclassified to conform to the new presentation. This segment reporting change has no impact on consolidated operating results.
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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.
The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.
Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers." See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's revenue recognition.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
Accounting for Asset Retirement Obligations: The Company's asset retirement obligations are principally for costs to close its surface mines and reclaim the land it has disturbed as a result of its normal mining activities as well as for costs to dismantle certain mining equipment at the end of the life of the mine. Under certain federal and state regulations, the Company is required to reclaim land disturbed as a result of mining. The Company determined the amounts of these obligations based on cost estimates, adjusted for inflation, projected to the estimated closure dates, and then discounted using a credit-adjusted risk-free interest rate. Changes in any of these estimates could materially change the Company's estimates for these asset retirement obligations causing a related increase or decrease in reported net operating results in the period of change in the estimate. The accretion of the liability is being recognized over the estimated life of each individual asset retirement obligation. The Company has capitalized an asset’s retirement cost as part of the cost of the related long-lived asset. These capitalized amounts are subsequently amortized to expense using a systematic and rational method.
Bellaire is a non-operating subsidiary of the Company with legacy liabilities relating to closed mining operations, primarily former Eastern U.S. underground coal mining operations. These legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. The Company determined the amounts of these obligations based on cost estimates, adjusted for inflation, and then discounted using a credit-adjusted risk-free interest rate. The accretion of the liability is recognized over the estimated life of the asset retirement obligation. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized.
Changes in any of these estimates could materially change the Company's estimates for these asset retirement obligations causing a related increase or decrease in reported net operating income in the period of change in the estimate. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
Long-lived assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company recognized charges of $7.3 million in the Minerals Management segment and $1.1 million in the Coal Mining segment to write-off certain capitalized leasehold costs, prepaid royalties and other assets during 2020.
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.
Income taxes: Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.
The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.
Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position.
See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
CONSOLIDATED FINANCIAL SUMMARY
The results of operations for NACCO were as follows for the years ended December 31:
2020 2019
Revenues:
Coal Mining $ 72,088 $ 68,701
NAMining 42,392 42,823
Minerals Management 14,721 30,119
Unallocated Items 2,133 790
Eliminations (2,902) (1,443)
Total revenue $ 128,432 $ 140,990
Operating profit (loss):
Coal Mining $ 25,436 $ 34,120
NAMining 1,872 (564)
Minerals Management 3,493 25,721
Unallocated Items (17,256) (20,713)
Eliminations (97) 256
Total operating profit $ 13,448 $ 38,820
Interest expense 1,354 872
Interest income (1,200) (3,616)
Income from other unconsolidated affiliates (239) (1,300)
Closed mine obligations 1,641 1,537
Gain on equity securities (1,226) (1,545)
Other, net (1,140) (527)
Other income, net (810) (4,579)
Income before income tax (benefit) provision 14,258 43,399
Income tax (benefit) provision (535) 3,767
Net income $ 14,793 $ 39,632
Effective income tax rate (3.8) % 8.7 %
The components of the change in revenues and operating profit are discussed below in "Segment Results."
Other (income) expense, net
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.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
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.
Gain on equity securities represents changes in the market price of invested assets reported at fair value. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Mine Water Treatment Trust.
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.
Income Taxes
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.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following tables detail the change in cash flow for the years ended December 31:
2020 2019 Change
Operating activities:
Net income $ 14,793 $ 39,632 $ (24,839)
Depreciation, depletion and amortization 18,114 16,240 1,874
Deferred income taxes 7,517 8,698 (1,181)
Stock-based compensation 3,078 4,924 (1,846)
Gain on sale of assets (269) (206) (63)
Inventory impairment charge 1,973 - 1,973
Other asset impairment charge 8,359 - 8,359
Other (3,452) (7,071) 3,619
Working capital changes (52,599) (9,433) (43,166)
Net cash (used by) provided by operating activities (2,486) 52,784 (55,270)
Investing activities:
Expenditures for property, plant and equipment and acquisition of mineral interests (44,368) (24,664) (19,704)
Proceeds from the sale of assets 571 4,572 (4,001)
Other (2,187) (170) (2,017)
Net cash used for investing activities (45,984) (20,262) (25,722)
Cash flow before financing activities $ (48,470) $ 32,522 $ (80,992)
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:
•Increased payments made under deferred compensation and long-term incentive compensation plans during 2020 compared with 2019.
•An increase in Accounts receivables during 2020 compared to a decrease during 2019. The large decrease in 2019 was primarily due to the timing of customer requirements at MLMC.
•A decrease in Accounts payable during 2020 compared to an increase during 2019 due to a change in timing.
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.
2020 2019 Change
Financing activities:
Net additions to long-term debt and revolving credit agreements 20,073 $ 13,258 $ 6,815
Cash dividends paid (5,375) (5,132) (243)
Other (670) (3,013) 2,343
Net cash provided by financing activities $ 14,028 $ 5,113 $ 8,915
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
The change in net cash provided by financing activities was primarily due to increased borrowings during 2020 compared with 2019.
Financing Activities
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.
NACoal has an unsecured revolving line of credit of up to $150.0 million (the “NACoal Facility”) that expires in August 2022. Borrowings outstanding under the NACoal Facility were $30.0 million at December 31, 2020. At December 31, 2020, the excess availability under the NACoal Facility was $117.0 million, which reflects a reduction for outstanding letters of credit of $3.0 million.
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.
Expenditures for property, plant and equipment and mineral interests
Following is a table which summarizes actual and planned expenditures (in millions):
Planned Actual Actual
2021 2020 2019
NACCO $ 46.6 $ 44.4 $ 24.7
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.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
Expenditures are expected to be funded from internally generated funds and/or bank borrowings.
Capital Structure
NACCO's consolidated capital structure is presented below:
December 31
2020 2019 Change
Cash and cash equivalents $ 88,450 $ 122,892 $ (34,442)
Other net tangible assets
244,907 174,465 70,442
Intangible assets, net 35,330 37,902 (2,572)
Net assets 368,687 335,259 33,428
Total debt (46,465) (24,943) (21,522)
Closed mine obligations (21,598) (20,924) (674)
Total equity $ 300,624 $ 289,392 $ 11,232
Debt to total capitalization 13 % 8 % 5 %
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.
Contractual Obligations, Contingent Liabilities and Commitments
NACCO adopted ASU 2016-02, “Leases (Topic 842)," on January 1, 2019. ASC 842 required a lessee to recognize a right-of-use asset and a corresponding lease liability for substantially all leases. See Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's leases.
Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company’s decisions to contribute above the minimum regulatory funding requirements. The Company does not expect to contribute to its pension plan in 2021. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.5 million in 2021 and approximately $0.5 million per year from 2022 through 2030. Benefit payments beyond that time cannot currently be estimated. All other pension benefit payments are made from assets of the pension plan. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2021 through 2030. Benefit payments beyond that time cannot currently be estimated.
NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.
NACoal is a party to certain guarantees related to Coyote Creek. The Company believes that the likelihood of NACoal’s future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.
ENVIRONMENTAL MATTERS
The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.
Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company’s policies stress environmental responsibility and compliance with these regulations. Based
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
on current information, management does not expect compliance with these regulations to have a material adverse effect on the Company’s financial condition or results of operations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.
SEGMENT RESULTS
COAL MINING SEGMENT
FINANCIAL REVIEW
Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31 (in millions):
2020 2019
Unconsolidated mines 28.5 32.0
Consolidated mines 2.5 2.6
Total tons delivered 31.0 34.6
Total coal reserves were as follows at December 31:
2020(1)
2019(1)
(in billions of tons)
Unconsolidated mines 1.0 1.0
Consolidated mines 0.9 1.0
Total coal reserves 1.9 2.0
(1)Amount includes 0.1 billion of coal reserves owned or controlled by customers as of both December 31, 2020 and December 31, 2019. The Company conducts activities to extract these customer-owned and controlled reserves.
The results of operations for the Coal Mining segment were as follows for the years ended December 31:
2020 2019
Revenues $ 72,088 $ 68,701
Cost of sales 70,452 65,430
Gross profit 1,636 3,271
Earnings of unconsolidated operations(a)
56,584 60,678
Selling, general and administrative expenses 30,216 27,394
Amortization of intangible assets 2,572 2,614
Gain on sale of assets (4) (179)
Operating profit $ 25,436 $ 34,120
(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2020 Compared with 2019
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
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
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
2019 $ 34,120
Increase (decrease) from:
Earnings of unconsolidated operations (4,094)
MLMC 's inventory impairment charge (1,973)
Gross profit, excluding revisions to Centennial's asset retirement obligation and MLMC's inventory impairment charge (1,741)
Voluntary separation program ("VSP") charge (1,475)
Selling, general and administrative expenses, excluding VSP charge (1,347)
Net gain on sale of assets (175)
Revisions to Centennial's asset retirement obligation 2,079
Amortization of intangibles 42
2020 $ 25,436
Operating profit decreased $8.7 million in 2020 compared with 2019. The change in operating profit was primarily due to:
•A decrease in earnings of unconsolidated operations, mainly due to a reduction in tons delivered as a result of decreases in customer demand and the termination of the Camino Real contract mining agreement during 2020.
•A $2.0 million inventory impairment charge at MLMC as mining costs exceeded net realizable value.
•A reduction in gross profit due to wind-down and employee-related expenses at Camino Real.
•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 Coal Mining segment recorded a charge of $1.5 million related to one-time termination benefits.
•An increase in selling, general and administrative expenses due to a $1.1 million asset impairment charge, higher professional fees, outside service fees and insurance costs, partially offset by lower employee-related expenses.
•The favorable net change in Centennial's asset retirement obligation is attributable to the absence of a $2.5 million unfavorable revision that occurred during 2019, partially offset by a $0.4 million unfavorable revision that occurred during 2020. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
NORTH AMERICAN MINING ("NAMining") SEGMENT
FINANCIAL REVIEW
Tons of limestone delivered by the NAMining segment were as follows for the years ended December 31 (in millions):
2020 2019
Unconsolidated operations 9.4 8.3
Consolidated operations 36.5 36.4
Total tons delivered 45.9 44.7
The results of operations for the NAMining segment were as follows for the years ended December 31:
2020 2019
Revenues $ 42,392 $ 42,823
Cost of sales 39,266 41,698
Gross profit 3,126 1,125
Earnings of unconsolidated operations(a)
3,619 3,205
Selling, general and administrative expenses 5,138 4,921
Gain on sale of assets (265) (27)
Operating profit (loss) $ 1,872 $ (564)
(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2020 Compared with 2019
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.
Operating Profit (Loss)
2019 $ (564)
Increase (decrease) from:
Gross profit 2,001
Earnings of unconsolidated operations 414
Net gain on sale of assets 238
Selling, general and administrative expenses (217)
2020 $ 1,872
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.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
MINERALS MANAGEMENT SEGMENT
FINANCIAL REVIEW
The results of operations for the Minerals Management segment were as follows for the years ended December 31:
2020 2019
Revenues $ 14,721 $ 30,119
Cost of sales 2,342 3,465
Gross profit 12,379 26,654
Selling, general and administrative expenses 8,886 933
Operating profit $ 3,493 $ 25,721
2020 Compared with 2019
Revenues and operating profit decreased in 2020 compared with 2019 as 2019 included significant royalty income generated by a large number of new gas wells put into commission in Ohio during 2018 and early 2019. These wells are operated by third parties to extract natural gas from the Company's Ohio Utica shale mineral reserves. Since new wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production, royalty income in 2020 decreased substantially from 2019 levels. Lower commodity prices in 2020 compared with 2019 also contributed to the reduction in revenues and operating profit. The increase in selling, general and administrative expenses is due to a $7.3 million asset impairment charge during 2020. The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company wrote-off certain capitalized leasehold costs and prepaid royalties related to legacy coal interests in 2020.
UNALLOCATED ITEMS AND ELIMINATIONS
FINANCIAL REVIEW
Unallocated Items and Eliminations were as follows for the years ended December 31:
2020 2019
Operating loss $ (17,353) $ (20,457)
2020 Compared with 2019
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.
NACCO Industries, Inc. Outlook
Coal Mining Outlook - 2021
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
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
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.
Changes in customer power plant dispatch, including changes related to natural gas price fluctuations and the continued increase in renewable generation, particularly wind, could reduce customer demand below anticipated levels, which could further unfavorably affect the Company’s 2021 outlook.
In May 2020, 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. GRE is willing to consider opportunities to sell Coal Creek Station, and NACCO is actively engaged in the exploration of options that could, if successful, allow for transfer of ownership of the power plant to one or more third parties, which would preserve jobs at both Coal Creek Station and the Falkirk Mine. Falkirk Mine is the sole supplier of lignite coal to Coal Creek Station pursuant to a long-term contract. The terms of the contract between the Company and GRE specify that GRE is responsible for all costs related to mine closure, including but not limited to, final mine reclamation costs, post-retirement medical benefits and pension costs with respect to Falkirk employees. This closure is not expected to affect 2021 results.
The owner of the power plant served by the Company's Sabine Mine in Texas intends to retire the power plant in 2023. The Sabine Mine contributed approximately $3.9 million to Earnings from Unconsolidated Operations in 2020. The terms of the contract between the Company and the customer specify that the customer is responsible for all costs related to mine closure, including but not limited to, final mine reclamation costs, post-retirement medical benefits and pension costs with respect to Sabine employees.
The closure of the power plants that are served by the Falkirk and Sabine Mines would have a material adverse effect on the future Earnings of unconsolidated operations of the Coal Mining segment and on the long-term earnings and cash flows of NACCO.
Capital expenditures are expected to be approximately $27 million in 2021. The elevated levels of capital expenditures in the Coal Mining segment from 2019 through 2021 relate to the development of a new mine area at MLMC. These increased capital expenditures will result in higher depreciation that will unfavorably affect operating profit in future periods. Capital expenditures for MLMC are expected to return to lower levels beginning in 2022 and continue through 2032, the end of the current contract term.
NAMining Outlook
In 2021, NAMining expects full year operating profit to increase moderately over 2020 with its existing customer contracts. NAMining is pursuing a number of growth initiatives that if successful would be accretive to future earnings.
Capital expenditures are expected to be approximately $9 million for the 2021 full year primarily for the acquisition, relocation and refurbishment of draglines.
In 2019, NAMining's subsidiary, Sawtooth Mining, LLC, entered into a mining agreement to serve as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada, owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). In January 2021, Thacker Pass received a Record of Decision from the U.S. Bureau of Land Management for the Thacker Pass project following the completion of the National Environmental Policy Act Process. This decision represents an important milestone in the development and the permitting of the Thacker Pass project. More permitting decisions are expected later in 2021 with production expected to begin in the second half of 2022.
Minerals Management Outlook
The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas and, to a lesser extent, oil, natural gas liquids and coal, extracted primarily by third parties. Excluding the impact of the $6.7 million write-off taken in 2020, operating profit in the Minerals Management
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
segment is expected to be down substantially in 2021 from 2020. This decrease is primarily related to a reduction in royalty income from existing Ohio mineral and royalty assets as a result of expected lower natural gas prices, fewer expected new wells in Ohio, lower commodity prices and the natural production decline that occurs early in the life of a well. Another sustained decline in natural gas prices could unfavorably affect the Company’s outlook.
Decline rates for individual wells can vary due to factors like well depth, well length, formation pressure and facility design. In addition, 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 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.
In 2020, the Minerals Management segment acquired mineral and royalty 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 and royalty 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. Including the 2020 acquisitions, total mineral and royalty interests include approximately 109.2 thousand gross acres and 58.1 thousand net royalty acres. Minerals Management is targeting additional investments in mineral and royalty interests of approximately $10 million in 2021. These investments are expected to be accretive to earnings, but each investment's contribution to earnings is dependent on the characteristics of each investment, including the size and type of interests acquired and the stage and timing of mineral development.
Consolidated 2021 Outlook
While the Company expects consolidated net income in 2021 to decrease significantly from 2020, management still continues to view the long-term business outlook positively because of a strong pipeline of potential new projects. The COVID-19 pandemic slowed certain business development initiatives in 2020, but the outlook for growth in the NAMining and Minerals Management segments and in the Company's Mitigation Resources of North America® business remains strong. Excluding the favorable impact of potential business development activities, the Company expects substantially lower pre-tax earnings as a result of lower operating profit, an anticipated increase in interest expense and a reduction in interest income. These lower pre-tax results are expected to be partially offset by an increase in the benefit from income taxes primarily due to the benefit from percentage depletion at certain of the Company's mining operations. Pre-tax income and net income are expected to be higher in the second half of 2021 than in the first half of 2021, primarily due to current expectations on the timing of customer requirements in the Coal Mining segment.
In light of ongoing regulatory, economic and public opinion challenges facing the coal-fired power generation industry, the Company commenced a voluntary separation program for certain corporate employees in the 2020 fourth quarter. The program was substantially completed by December 31, 2020. Estimated net benefits from this voluntary separation program are expected to be between $1.5 and $2.5 million annually beginning in 2021. As a result of this program and natural attrition, the number of headquarters employees was reduced by approximately 25%.
The Company’s cash flow before financing activities varies with changes in customer demand, particularly in the Coal Mining segment, as well as changes in earnings of the Minerals Management segment, working capital changes, capital expenditures, investments in royalty and mineral interests and changes in income taxes, as well as other factors. Cash flow before financing activities in 2020 included a significant use of cash related to changes in working capital, capital expenditures and the acquisition of mineral royalty interests. The Company anticipates positive cash flow before financing activities in 2021 but at a level still below the cash generated in 2019. Consolidated capital expenditures are expected to be approximately $46 million in 2021.
Significant uncertainties remain regarding the COVID-19 pandemic. The extent to which COVID-19 impacts the Company going forward will depend on numerous factors, including but not limited to the extent of new outbreaks, the extent to which additional stay-at-home orders may be imposed, the nature of the government public health guidelines and the public's adherence to those guidelines, the success of businesses reopening fully, the timing for proven treatments and the availability of vaccines for COVID-19. While the Company's existing mining operations to date have not been materially affected by the
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
pandemic, future developments, which are highly uncertain and unpredictable, could significantly and rapidly cause a deterioration in the Company’s results, supply chain channels and customer demand.
Growth and Diversification
The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses.
NAMining is pursuing growth and diversification by expanding the scope of its business development activities to include potential customers who require a broad range of minerals and materials and by leveraging the Company’s core mining skills to expand the range of contract mining services it provides. In addition, NAMining is pursuing opportunities to provide comprehensive mining services to operate entire mines when appropriate, as is the case at the new lithium project in Nevada.
The Minerals Management segment continues its efforts to grow and diversify by pursuing acquisitions of additional mineral and royalty interests in the United States, in what the Company believes is a buyer-friendly market. Once mineral and royalty interests have been acquired, the Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment. 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 continues to expand its business, which 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 and a strong reputation. The MRNA business has achieved several successes and is positioned for additional growth.
The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing 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 continues to look for opportunities to expand its coal mining business where it can apply its management fee business model to assume operation of existing surface coal mining operations in the United States. However, opportunities are very limited in the current environment. 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. In addition, 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.
The Company is committed to maintaining a conservative capital structure while it grows and diversifies without unnecessary risk, which will allow for strategic growth and increased free cash flow to re-invest in and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety and environmental stewardship.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Note 2 to the Consolidated Financial Statements in this Form 10-K for a description of recently issued accounting standards, if any, including actual and expected dates of adoption and effects to the Company's Consolidated Financial Statements.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
FORWARD-LOOKING STATEMENTS
The statements contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere throughout this Annual Report on Form 10-K that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of a long-term mining contract, or a customer default under a contract, (2) the impact of the COVID-19 pandemic, (3) a significant reduction in purchases by the Company's customers, including changes in coal consumption patterns of U.S. electric power generators, or changes in the power industry that would affect demand for the Company's coal and other mineral reserves, (4) changes in tax laws or regulatory requirements, including changes in mining or power plant emission regulations and health, safety or environmental legislation, (5) the ability of the Company to access credit in the current economic environment, or obtain financing at reasonable rates, or at all, as a result of current market sentiment for fossil fuels, (6) failure to obtain adequate insurance coverages at reasonable rates, (7) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (8) regulatory actions, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (9) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (10) weather or equipment problems that could affect deliveries to customers, (11) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing; and the ability of lessees to obtain capital or financing needed for well development operations and leasing and development of oil and gas reserves on federal lands, (12) changes in the costs to reclaim mining areas, (13) costs to pursue and develop new mining and value-added service opportunities, (14) delays or reductions in coal or aggregates deliveries, (15) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas and oil, (16) the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (17) the effects of receiving low sustainability scores which could result in the exclusion of the Company's securities from consideration by certain investment funds, and (18) disruptions from natural or human causes, including severe weather, accidents, fires, earthquakes and terrorist acts, any of which could result in suspension of operations or harm to people or the environment.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item 8 is set forth in the Financial Statements and Supplementary Data contained in Part IV of this Form 10-K and is hereby incorporated herein by reference to such information.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, 2020 that require disclosure pursuant to this Item 9.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures: An evaluation was carried out under the supervision and with the participation of the Company's management, including the principal executive officer and the principal financial officer, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that the Company's disclosure controls and procedures are effective.
Management's report on internal control over financial reporting: Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2020. The Company's effectiveness of internal control over financial reporting as of December 31, 2020 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.
Changes in internal control: There have been no changes in the Company's internal control over financial reporting, that occurred during the fourth quarter of 2020, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information with respect to Directors of the Company will be set forth in the 2021 Proxy Statement under the subheadings “Part III - Proposals To Be Voted On At The 2021 Annual Meeting - Proposal 1 - Election of Directors,” which information is incorporated herein by reference.
Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the 2021 Proxy Statement under the subheading “Part I - Corporate Governance Information - Directors' Meetings and Committees,” which information is incorporated herein by reference.
Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by the Company's Directors, executive officers and holders of more than ten percent of the Company's equity securities will be set forth in the 2021 Proxy Statement under the subheading “Part IV - Other Important Information - Delinquent Section 16(a) Reports,” which information is incorporated herein by reference.
The Company has adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the “Code of Corporate Conduct,” is posted on the Company's website at www.nacco.com under “Corporate Governance.” If the Company makes any amendments to or grants any waivers from the code of business conduct and ethics which are required to be disclosed pursuant to the Securities and Exchange Act of 1934, the Company will make such disclosure on the NACCO website.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. EXECUTIVE COMPENSATION
Information with respect to executive compensation will be set forth in the 2021 Proxy Statement under the headings “Part II - Executive Compensation Information” and “Part III - Proposals To Be Voted On At The 2021 Annual Meeting - Proposal 1 - Election of Directors,” which information is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information with respect to security ownership of certain beneficial owners and management will be set forth in the 2021 Proxy Statement under the subheading “Part IV - Other Important Information - Beneficial Ownership of Class A Common and Class B Common,” which information is incorporated herein by reference.
Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the 2021 Proxy Statement under the subheading “Part IV - Other Important Information - Equity Compensation Plan Information," which information is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information with respect to certain relationships and related transactions will be set forth in the 2021 Proxy Statement under the subheadings “Part I - Corporate Governance Information - Review and Approval of Related-Person Transactions,” which information is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information with respect to principal accountant fees and services will be set forth in the 2021 Proxy Statement under the heading “Part III - Proposals To Be Voted On At The 2021 Annual Meeting - Proposal 4 - Ratification of the Appointment of Company's Independent Registered Public Accounting Firm,” which information is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page of this Form 10-K.
(b) Financial Statement Schedules - The response to Item 15(c) is set forth beginning at page of this Form 10-K.
(c) Exhibits required by Item 601 of Regulation S-K
Exhibit Number Exhibit Description
(3) Articles of Incorporation and By-laws.
3.1(i) Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
3.1(ii) Amended and Restated By-laws of the Company are incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed by the Company on December 18, 2014, Commission File Number 1-9172.
(4) Instruments defining the rights of security holders, including indentures.
4.1 The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
4.2 The Mortgage and Security Agreement, dated April 8, 1976, between The Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(ii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
4.3 Amendment No. 1 to the Mortgage and Security Agreement, dated as of December 15, 1993, between Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(iii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File Number 1-9172.
4.4 Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed by the Company on October 5, 2017, Commission File Number 1-9172.
4.5 Amendment to Amended and Restated Stockholders' Agreement, dated as of February 14, 2019, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
4.6 Second Amendment to Amended and Restated Stockholders' Agreement, dated as of February 12, 2021, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 60 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2021, Commission File Number 1-9172.
4.7 Description of Securities is incorporated herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
Exhibit Number Exhibit Description
(10) Material contracts
10.1* NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan (Amended and Restated March 1, 2012) is incorporated herein by reference to Appendix B to NACCO's Definitive Proxy Statement, filed by NACCO on March 16, 2012, Commission File Number 1-9172.
10.2* NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2019) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 8, 2019, Commission File Number 1-9172.
10.3* NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 8, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 8, 2019, Commission File Number 1-9172.
10.4* Form of Award Agreement for the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan is incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed by the Company on September 17, 2012, Commission File Number 1-9172.
10.5* Form of Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.6* Form of Non-Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.7 Separation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.1 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.
10.8 Tax Allocation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.3 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.
10.9 Consulting Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.5 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on October 5, 2017, Commission File Number 1-9172.
10.10 Amendment to Consulting Agreement, dated as of December 15, 2020, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 15, 2020, Commission File Number 1-9172.
10.11 Transfer Restriction Agreement, dated as of September 29, 2017, by and among the Issuer, NACCO and the signatories thereto, is incorporated by reference to Exhibit 2 of Hamilton Beach Brands Holding Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on October 6, 2017, Commission File Number 1-9172.
10.12* NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.
10.13* The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.
10.14* Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.
10.15* The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.
10.16* Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.
10.17 Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.18 First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
Exhibit Number Exhibit Description
10.19 Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.20 Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.21 First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.22 Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.23 First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.+
10.24 Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.25 Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.26 Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.27 Second Restatement of Coal Sales Agreement by and between The Falkirk Mining Company and Great River Energy, dated as of January 1, 2007, is incorporated herein by reference to Exhibit 10.18 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.28 Amendment No. 1 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of January 21, 2011, is incorporated herein by reference to Exhibit 10.19 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.29 Amendment No. 2 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of March 1, 2014, is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, Commission File Number 1-9172.
10.30 Amendment No. 3 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of January 1, 2019, is incorporated herein by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.31 Restatement of Option Agreement by and among The Falkirk Mining Company, Cooperative Power Association, United Power Association, and the State of North Dakota, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.20 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.32 Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.21 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.33 Amendment No. 1 to Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of October 18, 2013 is incorporated herein by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
Exhibit Number Exhibit Description
10.34 Option Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981, is incorporated herein by reference to Exhibit 10.22 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.35 Addendum to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981 is incorporated herein by reference to Exhibit 10.23 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.36 Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of December 2, 1996, is incorporated herein by reference to Exhibit 10.24 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.37 Second Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Regions Bank, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.25 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.38 Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company, Texas Commerce Bank-Longview, Nortex Mining Company and The Sabine Mining Company, dated as of June 30, 1988, is incorporated herein by reference to Exhibit 10.26 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.39 Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++
10.40 First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.
10.41 Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.42* Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.
10.43* Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.44* Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.
10.45* Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.
10.46 Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.47 The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.
10.48 Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of August 11, 2017 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on August 15, 2017, Commission File Number 1-9172.
(21) Subsidiaries. A list of the subsidiaries of the Company is attached hereto as Exhibit 21.
(23) Consents of experts and counsel.
23.1 Consents of experts and counsel.
(24) Powers of Attorney.
24.1 A copy of a power of attorney for John S. Dalrymple is attached hereto as Exhibit 24.1.
24.2 A copy of a power of attorney for John P. Jumper is attached hereto as Exhibit 24.2.
24.3 A copy of a power of attorney for Dennis W. LaBarre is attached hereto as Exhibit 24.3.
24.4 A copy of a power of attorney for Michael S. Miller is attached hereto as Exhibit 24.4.
24.5 A copy of a power of attorney for Richard de J. Osborne is attached hereto as Exhibit 24.5.
24.6 A copy of a power of attorney for Alfred M. Rankin, Jr. is attached hereto as Exhibit 24.6.
24.7 A copy of a power of attorney for Matthew M. Rankin is attached hereto as Exhibit 24.7.
24.8 A copy of a power of attorney for Roger F. Rankin is attached hereto as Exhibit 24.8.
24.9 A copy of a power of attorney for Lori J. Robinson is attached hereto as Exhibit 24.9.
24.10 A copy of a power of attorney for Robert S. Shapard is attached hereto as Exhibit 24.10.
24.11 A copy of a power of attorney for Britton T. Taplin is attached hereto as Exhibit 24.11.
(31) Rule 13a-14(a)/15d-14(a) Certifications.
31(i)(1) Certification of J.C. Butler, Jr. pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(1).
31(i)(2) Certification of Elizabeth I. Loveman pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(2).
(32) Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed and dated by J.C. Butler, Jr. and Elizabeth I. Loveman.
(95) Mine Safety Disclosure Exhibit is attached hereto as Exhibit 95.
101.INS Inline XBRL Instance Document
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Management contract or compensation plan or arrangement required to be filed as an exhibit pursuant to Item15(b) of this Annual Report on Form 10-K.
** Filed herewith.
+ Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated March 27, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating "Confidential treatment requested".
++ Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated April 2, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating "Confidential treatment requested".