What changed in this filing

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Item 1. Business

2021-03-03 compared with 2020-03-04 · 498 added, 308 removed, 425 unchanged (65% of the section changed)

NACCO Industries, Inc.

® (“NACCO” or the “parent company”) is the public holding company for The North American Coal Corporation ® ("NACoal").

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 and its wholly-owned subsidiaries (collectively, "NACCO Industries, Inc.

and Subsidiaries" or the "Company") operate in the mining and natural resources industries through three operating segments:

® (“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 activated carbon producers pursuant to a service-based business model.

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 promotes the development of the Company’s oil, gas and coal reserves, generating income primarily from royalty-based lease payments from third parties.

The Company also has costs not directly attributable to a reportable segment which are not included as part of the measurement of segment operating profit, primarily administrative costs related to public company reporting requirements, the financial results of the Company’s mitigation banking business, Mitigation Resources of North America ® (“MRNA”), and Bellaire Corporation (“Bellaire”).

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.

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underground mining activities.

Included within other income is the financial results of NoDak Energy Services, LLC ("NoDak").

NoDak operates and maintains a coal drying system at a customer’s power plant.

The NoDak contract expired in the first quarter of 2020.

The following map shows our current operations:

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

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.

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.

Lithium Nevada is in the process of securing permits and currently expects to commence construction in 2021 and production of lithium products in 2023.

During the development of the project, Sawtooth Mining will provide Lithium Nevada $3.5 million in cash, of which $1.5 million has been provided as of December 31, 2019, to assist in project development.

Sawtooth Mining will also provide certain engineering services related primarily to mine design and permitting.

Under the terms of the mining agreement, Lithium Nevada will pay Sawtooth Mining a success fee upon achievement of certain engineering, construction and production milestones.

After Lithium Nevada secures required permits and financing for the project, Sawtooth Mining intends to acquire up to $50 million of mining equipment.

The cost of this mining equipment will be reimbursed to Sawtooth Mining by Lithium Nevada over a six-year period from the equipment acquisition date.

NAMining serves as a platform for pursuing non-coal mining projects by leveraging the Company's core mining capabilities.

In addition to the Thacker Pass Project, NAMining has grown from serving two customers at seven quarries utilizing 10 draglines in 2015 to serving 10 customers at 20 quarries utilizing 31 draglines and a rope shovel during 2019.

On September 29, 2017, the Company spun-off Hamilton Beach Brands Holding Company ("HBBHC"), a former wholly owned subsidiary.

As a result of the spin-off, NACCO stockholders received one share of HBBHC Class A common stock and one share of HBBHC Class B common stock for each share of NACCO Class A or Class B common stock owned on the record date for the spin-off.

On June 28, 2017, Southern Company and its subsidiary, Mississippi Power, suspended operations involving the coal gasifier portion of the Kemper County energy facility.

Liberty Fuels Company, LLC ("Liberty") was the sole supplier of coal to fuel the gasifier under its contract with Mississippi Power.

Liberty ceased all mining and delivery of lignite in 2017.

The terms of the contract specified that Mississippi Power was responsible for all mine closure costs and Liberty receives compensation for providing mine reclamation services.

As of December 31, 2019, the mine areas have been reclaimed and final mine reclamation activities, primarily monitoring, will continue until final bond release.

Bisti Fuels LLC (“Bisti”) became the contract miner at Navajo Transitional Energy Company's ("NTEC's") existing Navajo Mine on January 1, 2017.

Under the 15 year Contract Mining Agreement, the Company is reimbursed for actual costs incurred and is paid a management fee per MMBtu delivered.

Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker to decide how to allocate resources and to assess performance.

In the first quarter of 2019, the Company changed its reportable segments to reflect changes in the business, including growth at NAMining and Minerals Management.

As of January 1, 2019, the Company’s operating segments are:

(i) Coal Mining, (ii) NAMining and (iii) Minerals Management.

While the Company continues to pursue opportunities to add new coal mining operations to the Coal Mining segment, the NAMining segment will serve as the platform for pursuing non-coal mining projects and the Minerals Management segment will work to capitalize on the Company’s oil, gas and coal reserves.

Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II of this Form 10-K and in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

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 operates surface coal mines under long-term contracts with power generation companies and activated carbon producers pursuant to a service-based business model.

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 operations.

The operating coal mines are:

Bisti, Caddo Creek Resources Company, LLC (“Caddo Creek”), Camino Real Fuels, LLC (“Camino Real”), The Coteau Properties Company (“Coteau”), Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), The Falkirk Mining Company (“Falkirk”), Mississippi Lignite Mining Company (“MLMC”) and The Sabine Mining Company (“Sabine”).

Liberty is also included in the Coal Mining segment.

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 and Camino Real supply sub-bituminous and bituminous coal, respectively, for power generation.

Caddo Creek and Demery supply 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 activated carbon processing facilities under long-term supply contracts.

With the exception of Camino Real, each mine is the exclusive supplier of coal to its customers' facilities.

Camino Real’s customer takes all coal produced by the mine but also purchases additional coal from other suppliers.

This segment has a strong history of customer retention due to the long-term nature of its contracts and the proximity of the Company’s mines to its customers’ facilities.

With the exception of Camino Real, whose contract expires in 2021 but has renewal provisions, other contract expiration dates range from 2022 through 2045.

The contract that expires in 2022 may be extended for three additional periods of five years each, or until 2037, at the Company’s option.

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.

The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine.

This contract structure eliminates exposure to spot coal market price fluctuations while providing steady income and cash flow with minimal capital investment.

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.

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Instead, these contracts are accounted for as equity method investments.

The income before income taxes associated with these VIE's 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 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.

therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities.

The contracts for certain of the Company's Unconsolidated Subsidiaries permit or obligate the customer under some conditions to acquire the assets or stock of the subsidiary for an amount roughly equal to book value.

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;

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inflation rates.

Profitability at MLMC is affected by customer demand for coal, changes in the indices that determine sales price and actual costs incurred.

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.

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The decision of which power plants to dispatch is determined by TVA.

Centennial Natural Resources (“Centennial”), located in Alabama, ceased coal production at the end of 2015.

Since 2015, the Company has sold or transferred certain Centennial equipment and mineral reserves.

The Company continues to evaluate strategies for the remaining mineral reserves and a dragline, which have no remaining book value.

Cash expenditures related to mine reclamation at Centennial will continue until mine reclamation is complete, or ownership of, or responsibility for, the remaining mines is transferred.

Centennial is a consolidated entity within the Coal Mining segment as the Company is responsible for carrying costs and final mine reclamation.

The coal reserves at Coteau, Falkirk, Coyote, MLMC and Centennial are owned or controlled by the Company.

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.

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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.

certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities.

To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

The contracts under which certain of the Unconsolidated Subsidiaries operate provide that, under certain conditions, including default, the customer(s) involved may elect or be obligated to acquire the assets (subject to the liabilities) or the capital stock of the Coal Mining subsidiary for an amount effectively equal to book value.

The Company does not know of any conditions of default that currently exist.

North American Mining Segment

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 outside of the coal industry.

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.

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NAMining operates primarily at limestone quarries in Florida, but is focused on expanding outside of Florida and into mining materials other than limestone.

During 2019, the Company entered into a mining agreement to serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

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 promotes the development of the Company’s oil, gas and coal reserves, generating income primarily from royalty-based lease payments from third parties.

The Company’s gas, oil and undeveloped coal reserves are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal and coalbed methane and natural gas) and North Dakota (coal).

The majority of the Company’s existing reserves were acquired as part of its historical coal mining operations.

The Minerals Management segment derives income primarily by entering into contracts with third-party operators, granting them the rights to explore, produce and sell natural resources in exchange for royalty payments based on the lessees' sales of natural gas and, to a lesser extent, oil and coal.

Specialized employees in the Minerals Management segment also provide surface and mineral acquisition and lease maintenance services related to Company operations.

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

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:

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.

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 coal producers.

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.

In 2018 and 2017, two customers 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

Choctaw Generation Limited Partnership, LLLP

Ascent Resources

Minerals Management

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;

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.

For the year ended December 31, 2019 , the Coal Mining segment derived approximately 60% of the Earnings of Unconsolidated Operations from two customers, Basin Electric Power Cooperative and Great River Energy.

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 results of operations.

The Company has a strong history of customer retention due to the long-term nature of its contracts and the proximity of the Company’s coal mines to its customers’ facilities.

The 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.

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 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.

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Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources competitive with coal.

The power plants the Coal Mining segment supplies are generally younger and more efficient, with better environmental controls than most plants that have closed in recent years.

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, 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 ten largest coal producers in the U.S.

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, primarily from aggregates producers which choose to self-perform mining operations.

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

In the Minerals Management segment, the oil and gas industry is intensely competitive;

the Company primarily competes with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and who may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than the Company’s financial or human resources permit.

Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties.

Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position.

The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer.

The Minerals Management segment’s ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, because the Company has fewer financial and human resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.

The Company has experienced limited variability in its results due to the effect of seasonality;

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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 and seasonal weather conditions, both of which can result in variations in limestone demand.

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 and coal, extracted primarily by third parties.

Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production.

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.

lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

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 its current labor relations with both union and non-union employees are satisfactory.

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

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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:

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Proven and Probable Reserves (a)(b)

(Millions of Tons)

Contract Uncommitted Total Tons

(Millions) Owned

(Millions) Contract

Mine/Reserve Type of Mine (Millions of Tons)

Unconsolidated Mines

Freedom Mine (c)-

The Coteau Properties Company

Surface Lignite

Falkirk Mine (c)-

The Falkirk Mining Company

Surface Lignite

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)(e)-

The Sabine Mining Company

Surface Lignite

Five Forks Mine (c)(e)-

Demery Resources Company, LLC

Surface Lignite

Marshall Mine (c)(e)-

Caddo Creek Resources Company, LLC

Surface Lignite

Eagle Pass Mine (c)(e)-

Camino Real Fuels, LLC

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

Navajo Mine (c)(f)- Bisti Fuels Company

Sub-bituminous

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

Centennial Natural Resources

Surface Bituminous

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 —

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Average Coal Quality (As received)

Coal Formation or

Thickness (feet)

Mine/Reserve Type of Mine Coal Formation or

Coal Seam(s) Average Seam

Thickness (feet) Average

Depth (feet) BTUs/lb Sulfur

(%) Moisture (%)

Unconsolidated Mines

Freedom Mine (c)-

The Coteau Properties Company

Surface Lignite

Beulah-Zap Seam

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

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)(e)-

The Sabine Mining Company

Surface Lignite

Wilcox Formation

Five Forks Mine (c)(e)-

Demery Resources Company, LLC

Surface Lignite

Wilcox Formation I Seam

Marshall Mine (c)(e)-

Caddo Creek Resources Company, LLC

Surface Lignite

Wilcox Formation A Seam

Eagle Pass Mine (c)(e)-

Camino Real Fuels, LLC

Surface Bituminous

Olmos Formation

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

Navajo Mine (c)(f)- Bisti Fuels Company

Sub-bituminous

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

Centennial Natural Resources

Surface Bituminous

Black Creek, New Castle, Mary Lee, Jefferson, American, Nickel Plate, Pratt Seams

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

Fort Union Formation

Wilcox Formation

Freeport & Kittanning Seams

Wilcox Formation

Committed and uncommitted tons represent in-place estimates.

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.

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.

(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.

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See footnote (h) for coal reserves currently leased to others.

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.

Although the term of the existing coal sales agreement terminates in 2022, the term may be extended for three additional periods of five years, or until 2037, at the option of the Company.

These reserves are owned or controlled by customers.

(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.

These reserves are owned or controlled by Bisti's customer and it controls proven and probable reserve data.

(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.

Centennial ceased active mining operations at the end of 2015.

The proven and probable reserves included in the table do not include coal that is leased to others.

(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.

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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 Power Cooperative.

Dakota Coal Company then sells the coal to the Great Plains Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric Power Cooperative.

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.

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.

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Falkirk Mine — The Falkirk Mining Company

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually primarily for the Coal Creek Station, an electric power generating station owned by Great River Energy.

The mine started delivering coal in 1978.

Commencing in the second half of 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by Great River Energy.

Annual deliveries to Spiritwood Station have averaged between 200,000 and 400,000 tons.

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.

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The South Hallsville No.

1 Mine generally produces between 2.5 million and 3.5 million tons of lignite coal annually.

The mine started delivering coal in 1985.

All production from the mine is delivered to Southwestern Electric Power Company's Henry W.

Pirkey Plant.

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.

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Marshall Mine — Caddo Creek Resources Company, LLC

The Marshall Mine, operated by Caddo Creek, began delivering coal in 2014 and is located approximately ten miles south of Marshall, Texas on FM-1186.

Access to the Marshall Mine is by means of a paved road.

Caddo Creek has no title, claim, lease or option to acquire any of the reserves at the Marshall Mine.

Caddo Creek's customer, Marshall Mine, LLC, controls all of the reserves within the Marshall Mine.

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.

The Eagle Pass Mine produces between 1.0 million and 2.0 million tons of bituminous coal annually.

Eagle Pass Mine is located approximately six miles north of Eagle Pass, Texas on State Highway 1588.

Access to the Eagle Pass Mine is by means of a paved road.

Camino Real has no title, claim, lease or option to acquire any of the reserves at the Eagle Pass Mine.

Camino Real's customer, Dos Republicas Coal Partnership, controls all of the reserves within the Eagle Pass Mine.

Liberty Mine — Liberty Fuels Company, LLC

In 2017, Mississippi Power instructed Liberty to permanently cease all mining and delivery of lignite and to commence mine reclamation.

The terms of the contract specified that Mississippi Power was responsible for all mine closure costs and Liberty receives compensation for providing mine reclamation services.

As of December 31, 2019, the mine areas have been reclaimed and final mine reclamation activities, primarily monitoring, will continue until final bond release.

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

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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 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 NTEC's Navajo Mine since 2017.

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.

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Centennial ceased active mining operations at the end of 2015.

Centennial and its affiliate, NACRC, own in fee approximately 5,602 acres of coal interests and approximately 2,323 acres of surface interests in Alabama.

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.

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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

Year NACCO Started Operations

White Rock — North

White Rock — South

Central State Aggregates

McDonald Group

Mid Coast Aggregates

Sumter County

McDonald Group

West Florida Aggregates

Hernando County

McDonald Group

Sumter County

Crystal River

Titan Corkscrew

Titan America

Palm Beach Aggregates

Martin Marietta

SDI Aggregates

Blue Water Industries

King William County, VA

King William Sand and Gravel Company, Inc.

K&M Pasco 130 Holdings, LLC

Alachua County

Argos USA, LLC

Location Name Location Customer Year NACCO Started Operations

White Rock — North Miami WRQ 1995

Krome Miami Cemex 2003

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

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.

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.

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Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.

Access to the West Florida mine is by means of a paved road from Cortez Boulevard.

Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.

Access to the St.

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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 121 st Way.

NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.

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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 the reserves within its mines through fee ownership, and leases and licenses from the coal and surface owners.

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.

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There were no previous operators of the Freedom Mine, Falkirk Mine, South Hallsville No.

1 Mine, Five Forks Mine, Marshall Mine, Eagle Pass Mine, Liberty Mine, Coyote Creek Mine or Red Hills Mine.

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.

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All coal mines are well past the exploration stage.

With the exceptions of Centennial and Liberty, additional pit development is under way at each mine.

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 six years of the current pit.

Drilling beyond the six-year horizon ranges from 1,000 to 2,000-foot centers.

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.

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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:

Mining Method

Total Historical Cost of Mine

Location Mining Method Total Historical Cost of Mine

Property, Plant and Equipment

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Unconsolidated Mining Operations

Freedom Mine — The Coteau Properties Company

Dragline operation with 3 draglines

Falkirk Mine — The Falkirk Mining Company

Dragline operation with 4 draglines

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

Five Forks Mine — Demery Resources Company, LLC

Truck-shovel operation

Marshall Mine — Caddo Creek Resources Company, LLC

Dragline operation with 1 dragline

Eagle Pass Mine — Camino Real Fuels, LLC

Truck-shovel operation

Coyote Creek Mine — Coyote Creek Mining Company, LLC

Dragline operation with 1 dragline

Navajo Mine — Bisti Fuels Company, LLC

Dragline operation with 2 draglines

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

(a) During 2019, NAMining operated 31 draglines at 20 quarries.

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.

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The excavated limestone is transported and processed by the customer.

Predominantly all of Bisti, Caddo Creek, Camino Real and Demery's machinery and equipment is owned by the customer of the respective mines.

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.

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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 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 Caddo Creek, Demery, Bisti and Camino Real;

however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.

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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

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Environmental Protection Agency (the “EPA”), the U.S.

Army Corps of Engineers and the OSMRE are 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.

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.

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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”).

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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.

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.

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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 is proposing to clarify the process for evaluating whether the New Source Review (NSR) permitting program would apply to proposed projects at existing air pollution sources.

This proposal would make 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”.

This clarification is expected to be finalized in 2020.

The remaining litigation and the uncertainty around the New Source Review Program rules could adversely impact demand for coal.

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.

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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.

In addition, the Company's power generation customers may choose to close coal-fired generation units or to postpone or cancel plans to add new capacity, in light of these costs and the limited time available for compliance with the requirements and the prospects of the imposition of additional future requirements on emissions from coal-fired units.

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.

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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 this finding, the EPA published a New Source Performance Standard for greenhouse gases, emitted from future new power plants.

In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce greenhouse gas emissions from existing electric generating units ("EGUs").

In contrast to the Clean Power Plan, the ACE rule limits "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.

Under ACE, states have the primary role in developing standards of performance that result from the application of BSER.

The EPA has not provided a standard of performance that it will deem presumptively acceptable in a state plan, but urges states to provide full justification for each component of their plans so that the EPA can evaluate BSER on a unit-by-unit basis.

States have until 2022 to develop and submit compliance plans to the EPA.

The EPA will have a year to review and approve the plans.

The states are given 24 months from the approval date to implement the rule and can extend the compliance schedule for units that meet progress milestones.

An EGU’s compliance with the ACE rule may not be required until 2024 or later.

Until states develop plans that are accepted by the EPA, the Company will not be able to determine the final impact of the rule.

T he 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.

has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005.

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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 2019, the United States submitted a formal notification of its withdrawal from the Paris Agreement.

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.

Signific ant public opposition has also been raised with respect to the proposed construction of certain new coal-fueled EGUs due to the potential for increased air emissions.

Signific ant 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.

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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 us 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.

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.

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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.

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.

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Army Corps of Engineers for operations in waters of the United States.

Bellaire Corporation, a wholly owned non-operating subsidiary of the Company (“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.

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.

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In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units.

The EPA is currently proposing additional changes to the CCR rule that would affect annual groundwater monitoring reporting requirements, environmental demonstration threshold, temporary placement of unencapsulated CCR on the land, and establish a new deadline for all unlined/non-compliant surface impoundments.These may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and may have an adverse impact on demand for coal.

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.

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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 disposing of CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

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.

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;

• 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.

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.

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.

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EXECUTIVE OFFICERS OF THE COMPANY

Current Position

Other Positions

President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from July 2015)

From prior to 2015 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO.

Name Age Current Position Other Positions

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").

From prior to 2015 to July 2015, Senior Vice President - Project Development, Administration and Mississippi Operations of NACoal.

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 2015 to September 2016, Associate, White and Case LLP (law firm).

Vice President and Controller and Principal Financial Officer (from prior to 2015)

Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2015)

From prior to 2015 to September 2017, Assistant Secretary of HBB and KC.

Associate General Counsel of NACCO (from prior to 2015), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2015) and President, North American Coal Royalty Company (an NACoal subsidiary) (from September 2015)

From prior to 2015 to September 2015, Director-Land of NACoal.

From prior to 2015 to September 2015, Assistant Secretary of NACCO.

Associate General Counsel and Assistant Secretary of NACCO (from May 2017), Associate General Counsel and Assistant Secretary of NACoal (from May 2017)

From January 2015 to April 2017, Senior Counsel, Locke Lord (law firm).

Vice President - Financial Planning and Analysis and

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).

Loveman 51 Vice President and Controller and Principal Financial Officer (from prior to 2016)

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.

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)

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).

Maxwell 43 Vice President - Financial Planning and Analysis and

Treasurer (from September 2017)

From September 2015 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.

From January 2014 to September 2015, Senior Manager, Finance and Assistant Treasurer.

From prior to 2016 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Current Position

Other Positions

Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017)

From prior to 2015 to November 2016, Vice President of Financial Planning and Analysis at Westmoreland Coal Company.

Vice President - Operations of NACoal (from January 2017)

From prior to 2015 to December 2016, President, The Coteau Properties Company (an NACoal subsidiary).

Name Age Current Position Other Positions

Anderson 45 President - MRNA (from March 2017) From prior to 2016 to February 2017, Environmental Manager, The Sabine Mining Company (an NACoal subsidiary)

Berry 53 President - NAMining (from prior to 2016)

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.

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.

Controller of NACoal (from September 2019)

From November 2017 to August 2019, Assistant Controller of NACoal.

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.

Vice President - Engineering and Business Development (from April 2019)

From May 2017 to March 2019, Vice President - Business Development.

From prior to 2015 to April 2017, President of Liberty.

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

Patrick Sullivan, Jr.

1 unchanged sentence

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business