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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-9172
NACCO INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
Delaware34-1505819
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
   
5875 Landerbrook Drive,Suite 220
Cleveland,Ohio 44124-4069
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (440229-5151

Securities registered pursuant to Section 12(b) of the Act
Title of each class
Trading Symbol
Name of each exchange on which registered
Class A Common Stock, $1 par value per shareNCNew York Stock Exchange
Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
     Yes ¨    No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
     Yes ¨    No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
     Yes þ     No £
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
     Yes þ     No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filerNon-accelerated filerSmaller reporting companyEmerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)
     Yes     No 
Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2021 (the last business day of the registrant's most recently completed second fiscal quarter): $109,032,630
Number of shares of Class A Common Stock outstanding at February 18, 2022: 5,616,768
Number of shares of Class B Common Stock outstanding at February 18, 2022: 1,566,413
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for its 2022 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.



NACCO INDUSTRIES, INC.
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PART I
Item 1. BUSINESS
General
NACCO Industries, Inc.® (“NACCO” or the “Company”) brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. In addition, Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

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

Business Strategy
During 2021, the Company launched a new branding campaign. The new branding creates a unified identity and underscores NACCO’s commitment to all of its businesses, while focusing on the execution of its two key strategies – Protect the Core and Grow and Diversify. NACCO’s portfolio of businesses now operates under the umbrella of NACCO Natural Resources. The new branding provides each business with its own unique identity that can easily be linked back to the NACCO legacy brand and includes new websites for each business, including NACCO Natural Resources, new business-specific logos and a new tagline “Bringing Natural Resources to Life”.

The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses. Management continues to be optimistic about the long-term outlook for growth in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification.

NAMining is pursuing growth and diversification by expanding the scope of its business development activities to include potential customers who require a broad range of minerals and materials and by leveraging the Company’s core mining skills to expand the range of contract mining services it provides. The goal is to build NAMining into a leading provider of contract mining services for customers who produce a wide variety of minerals and materials. The Company believes NAMining can grow to be a substantial contributor to operating profit, delivering unlevered after-tax returns on invested capital in the mid-teens as this business model matures and achieves significant scale, but the pace of achieving these objectives will be dependent on the mix and scale of new projects.

The Minerals Management segment continues to grow and diversify by selectively acquiring mineral and royalty interests in the United States, in a market and price environment that the Company believes remains well-aligned with its strategy and objectives. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as all further development costs are borne entirely by third-party producers who lease the minerals. The Company believes this business model can deliver substantial operating margins over the life of a reserve without the costs and risk that traditional oil and gas companies bear for the cost of exploration, production and/or development. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions, and has several potential acquisitions under review. The goal is to construct a diversified portfolio of high-quality oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the low-to-mid-teens as the portfolio of reserves and mineral interests grows and this business model matures.

Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. The Mitigation Resources business has achieved several early successes and is positioned for additional growth. The Company's
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goal is to grow Mitigation Resources into one of the ten largest U.S. providers of mitigation solutions, largely focused on streams and wetlands, initially in the southeast United States. While this business is in the early stages of development, the Company believes that Mitigation Resources can provide solid rates of return as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and availability of renewable energy sources, such as wind and solar, affect the amount of electricity dispatched from coal-fired power plants. Coal and natural gas traditionally have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. During 2021, however, natural gas prices were much higher than in recent years, generally resulting in increased dispatch of coal-fired power plants.

The Company continues to look for opportunities to expand its coal mining business where it can apply its management fee business model to assume operation of existing surface coal mining operations in the United States. However, opportunities are very limited in the current environment. In addition, the political and regulatory environment is not receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. 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. The Company is passionately committed to working hard, doing what’s right, and bringing America's natural resources to life.

Business Developments

Coal Mining Segment
Effective September 30, 2021, the contract mining agreement between Bisti Fuels Company, LLC (“Bisti”) and its customer, Navajo Transitional Energy Company ("NTEC") was terminated. As required under the agreement, NTEC paid the Company a termination fee of $10.3 million. As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.

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, owned by Dakota Gasification Company (“Dakota Gas’), a subsidiary of Basin Electric, that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. During 2020, Basin Electric informed 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. During August 2021, Bakken Energy (“Bakken”) and Basin Electric signed a non-binding term sheet to transfer ownership of the assets of Dakota Gas to Bakken. Bakken stated the closing date is expected to be April 1, 2023. As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close. 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.

The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant. Coal Creek Station and Spiritwood Station are owned by Great River Energy (“GRE”). In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas.

During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The
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closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.

Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will terminate. Falkirk and GRE have entered into a termination and release of claims agreement. Upon completion of the sale of Coal Creek Station, GRE will pay Falkirk $14.0 million in cash, as well as transfer ownership of an office building located in Bismarck, North Dakota, and convey membership units in Midwest AgEnergy to The North American Coal Corporation® (“NACoal”), a wholly-owned subsidiary of NACCO. NACCO currently holds a $5.0 million investment in Midwest AgEnergy, which operates two ethanol facilities in North Dakota.

If GRE's efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will supply all coal requirements of Coal Creek Station concurrent with Rainbow Energy’s acquisition of the power plant. Falkirk will no longer make any coal deliveries to GRE’s Spiritwood Station. Falkirk will be paid a management fee and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances. If Rainbow Energy terminates the CSA and closes Coal Creek Station before 2027, Falkirk will be entitled to an additional payment from GRE under the terms of the termination and release of claims agreement. The additional payment amount ranges from $8 million if the closure occurs before 2024 to $2 million if the closure occurs in 2026. To support the transfer to new ownership, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation.

If GRE’s efforts to sell the power plant are not successful and GRE elects to prematurely close Coal Creek Station, the early termination of the CSA would have a material adverse effect on the Company's business, financial condition and results of operations.

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. During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.

During 2020, Caddo Creek Resources Company, LLC (“Caddo Creek”) ceased all mining and delivery of lignite and commenced mine reclamation. Funding for mine reclamation is the responsibility of a subsidiary of Advanced Emissions Solutions (“AES”). Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation. The reclamation at Caddo Creek is expected to be substantially complete during the first half of 2022.

During 2020, the contract mining agreement between Camino Real Fuels, LLC (“Camino Real”) and its customer, Dos Republicas Coal Partnership (“DRCP”), terminated and resulted in mine closure. Funding for mine reclamation is the responsibility of DRCP.

NAMining Segment
In the third quarter of 2021, NAMining entered into contracts with a new customer to perform all mining operations at two sand and gravel quarries located in Texas and Arkansas. The initial term of each contract is two years, and one of the contracts automatically extends an additional two years provided NAMining is not in default under that contract. In the second quarter of 2021, NAMining entered into a one-year mining services contract with an existing customer for a sand and gravel quarry in Indiana. In the first quarter of 2021, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida. NAMining will operate two smaller draglines at this quarry while it relocates and commissions a larger dragline that will increase production capacity. The relocated dragline is anticipated to be commissioned in the second half of 2022. During 2021, NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida.

In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.
Thacker Pass is owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas Corp. owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium
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produced. At maturity, the Thacker Pass management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

Minerals Management Segment
During 2021 and 2020, the Minerals Management segment acquired additional mineral interests, primarily in the Eagle Ford and Permian Basins in Texas. During the second quarter of 2021, the Minerals Management segment, through its Catapult business, acquired a combination of mineral and overriding royalty interests in the Eagle Ford Basin, which includes approximately 14.1 thousand gross acres and 1.7 thousand net royalty acres, for an initial payment of $4.7 million. Under the terms of the transaction, Catapult could make additional payments for each additional well developed on the acquired assets during 2022 of up to a maximum of $0.6 million. Catapult also completed a small acquisition of royalty interests in the Delaware Basin during 2021 for a purchase price of $0.3 million. Minerals Management intends to continue to make future acquisitions of mineral and royalty interests that meet the Company’s acquisition criteria as part of its growth strategy.

Operations

Coal Mining Segment
The Coal Mining segment, 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 and Louisiana. Through September 30, 2021, the Company provided contract mining services on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.

During 2021, the Company's operating coal mines were: Bisti, 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. Demery supplies lignite coal for the production of activated carbon products. Each mine is the exclusive supplier of coal to its customers' facilities. Each of these mines delivers its coal production to adjacent or nearby power plants, synfuels plants or an activated carbon processing facility under long-term supply contracts. MLMC’s lignite sales agreement contains a minimum annual take provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate based on customer requirements. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

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

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

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

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Caddo Creek met the definition of a VIE prior to the cessation of mining on September 30, 2020. The terms of the contract to perform mine reclamation contain a fixed-price component and therefore, Caddo Creek has been consolidated within the Company's financial statements since October 1, 2020.

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

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

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

NAMining Segment
The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The segment is a primary platform for the Company’s growth and diversification of mining activities outside of the coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2021, NAMining operates mines in Florida, Texas, Arkansas and Indiana and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

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

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

The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) 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 basin 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 2021 and 2020 acquisitions of mineral and royalty interests was $5.3 million and $14.2 million, respectively. The 2021 acquisitions include 20.6 thousand gross acres and 1.8 thousand net royalty acres. The 2020 acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres. Total mineral and royalty interests include approximately 127.8 thousand gross acres and 59.9 thousand net royalty acres at December 31, 2021.

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),
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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. A holder of royalty interests is 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.

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's proved reserves.

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

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

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner and non-operator, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

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In 2021 and 2020, two customers individually accounted for more than 10% of consolidated revenues. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenues for those years:
Percentage of Consolidated Revenues
Segment20212020
Coal Mining customer43 %55 %
NAMining customer19 %19 %

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

In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE. The loss of either of these contracts could have a material adverse effect on the Earnings of Unconsolidated Operations of the Coal Mining segment and a material adverse effect on the Company's Consolidated Statements of Operations.

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

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

Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to continue to displace coal-fired electric baseload power generation in the near term. There also continues to be an increase in the amount of electricity generated by wind and solar. Fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. The significant increase in natural gas prices in 2021 compared to natural gas prices in 2020 contributed to an increase in customer power plant dispatch and coal deliveries in 2021. Sustained higher natural gas prices could lead to increased demand for coal and positively affect Coal Mining segment results. Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind. Federal and state mandates for increased use of electricity derived from renewable energy sources have also negatively affected demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources competitive with coal. The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began 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 will receive a 10% ITC. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2021 based on total coal tons produced.

NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.

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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 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 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 resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.

Seasonality
The Company has experienced limited variability in its results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns.

The NAMining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions and pandemics, all of which can result in variations in demand for aggregates.

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, geology, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of the Company's control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

Human Capital
As of December 31, 2021, the Company and its subsidiaries had approximately 1,600 employees, including approximately 1,100 employees at the Company’s unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes it has good relations with its employees.

Market-Based Compensation: NACCO believes its employees are critical to its success and invests in its employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives. The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. Benefits offered to employees include:

Medical, dental and vision benefits for employee, spouse and dependents;
Flexible spending accounts for both healthcare and dependent care;
Health savings accounts and health reimbursement accounts, both of which receive a company contribution;
Paid vacation and holidays;
Parental leave;
Short-term and long-term disability benefits;
Wellness incentives for employees;
Life and AD&D insurance benefits;
Charitable donation matches; and
Employee assistance program.

Employee Development: The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments that 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.
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Safety: Employee safety in the workplace is one of the Company’s core values. The Company is committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company believes communication related to “near misses,” safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.

Company Ethics: The Company has processes in place for compliance with its Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of the Company's Directors and employees annually complete certifications with respect to compliance with the Company's Code of Corporate Conduct. In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training. Ethics are deeply embedded in the Company’s values and business processes. The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.

Community Engagement: 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. Community engagement is encouraged and supported through the Company's matching gift program. The Company will match employee contributions up to $5,000 per employee if program criteria are met.

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

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

Government Regulation
The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment. Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of the Company’s Minerals Management segment.
Numerous governmental permits and approvals are required for coal mining operations. The Company's subsidiaries hold or will hold the necessary permits at all of its coal mining operations except Demery and Caddo Creek, 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 or reclaim Caddo Creek and Demery; however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.
At the coal mining operations where the Company's subsidiaries hold the permits, the Company is required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.
Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.
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Mine Health and Safety Laws
The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.
Environmental Laws
The Company's coal mining operations are subject to various federal environmental laws, as amended, including:
the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”);
the Clean Air Act, including amendments to that act in 1990 (“CAA”);
the Clean Water Act of 1972 (“CWA”);
the Resource Conservation and Recovery Act ("RCRA");
the National Environmental Policy Act of 1970 (“NEPA”); and
the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").
In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations. Both federal and state inspectors regularly visit mines to enforce compliance. The Company has ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Coal Mining segment.
Surface Mining Control and Reclamation Act
SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

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

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

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the “Fund”), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The 2021 Infrastructure Investment and Jobs Act reauthorized the Abandoned Mine Land fee at a reduced rate. The fee for lignite coal was reduced from $0.08 per ton to $0.064 per ton and for other surface-mined coal from $0.28 per ton to $0.224 per ton. These fees have been reauthorized until the end of fiscal year 2035.

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

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

The Company does not believe there is any significant risk to the Company's subsidiaries ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.
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Clean Air Act and Affordable Clean Energy Rule ("ACE")
The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.

States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone, and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years. In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In March 2021, EPA finalized the “Revised Cross-State Air Pollution Rule” to address the remand of the CSAPR update. The final rule requires no further obligations in states where the Company’s customers operate a power plant.

The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.

The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits. In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019. While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021. Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized. SIPs will be sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and
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Wildlife Service and the United States Forest Service and all corresponding public comment periods. See "Item 1A - “Risk Factors” on page 20 for further discussion of the regional haze program.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”. In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule; however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.

Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

The U.S. Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and “cap-and-trade” programs, and mandates or incentives to generate electricity by using renewable resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, the ACE rule limited "best system of emission reduction" ("BSER") to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and they vacated the ACE rule. In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants. In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States recently granted certiorari. The Supreme Court of the United States will hear the case in February 2022. Depending on the outcome of the Supreme Court ruling, the EPA may draft a new rule to regulate carbon dioxide 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.

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

As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change (“Paris Agreement”). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories. Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets. The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a materially adverse effect on the Company’s business, financial condition and results of operations.

Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.

The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.
Clean Water Act
The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR"). The new definition was challenged in court and two court cases resulted in vacatur of the NWPR. In December 2021, the EPA and COE released a draft “Step One” rule to redefine WOTUS by formally rescinding the NWPR and replacing it with a new definition. If the new definition is promulgated as drafted, some of the Company's operations could incur additional costs to mitigate streams and wetlands.

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

Bellaire was notified by the Pennsylvania Department of Environmental Protection ("DEP") during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust (the "Trust"). See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the Trust.
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Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In December 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule. One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. This new rule may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

National Environmental Policy Act
NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required information to the appropriate federal agency so that they may complete the environmental assessment. Historically, this process has been lengthy and may take several years to complete. In July 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations; however, it was immediately challenged by states and non-governmental organizations. In October 2021, the CEQ issued a new draft rule rescinding many of the revisions from 2020 update. If finalized as drafted, the revised NEPA regulations could adversely affect the Company’s ability to secure necessary permits.

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.

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Environmental Matters
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the Company’s mineral interests, which could materially adversely affect the Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company’s mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

Drilling and Production
The operations of the Company’s third-party lessees 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 states, and some counties and municipalities, in which the Company has mineral interests also regulate one or more of the following:
the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or "allowables";
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.

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

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

Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions.
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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
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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 operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues 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 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 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.

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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 allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but the Company cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.

Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

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

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

INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2022 the name, age, current position and principal occupation and employment during the past five years of the Company’s executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.


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EXECUTIVE OFFICERS OF THE COMPANY
NameAgeCurrent PositionOther Positions
J.C. Butler, Jr.61President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from prior to 2017)From prior to 2017 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO. From prior to 2017 to September 2017, Assistant Secretary of Hamilton Beach Brands ("HBB") and Kitchen Collection ("KC").
Matthew J. Dilluvio32 Associate Counsel and Assistant Secretary of NACCO and NACoal (from June 2019)From prior to 2017 to May 2019, Associate, Sidley Austin LLP (law firm).
Elizabeth I. Loveman52 Vice President and Controller and Principal Financial Officer (from prior to 2017)
John D. Neumann46 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2017)From prior to 2017 to September 2017, Assistant Secretary of HBB and KC.
Miles B. Haberer55 Associate General Counsel of NACCO (from prior to 2017), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2017) and President, North American Coal Royalty Company (an NACoal subsidiary) (from prior to 2017)    
                                                        
Sarah E. Fry46 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 2017 to April 2017, Senior Counsel, Locke Lord (law firm).
Thomas A. Maxwell44 Vice President - Financial Planning and Analysis and
Treasurer (from September 2017)

From prior to 2017 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.
PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES
NameAgeCurrent PositionOther Positions
Eric S. Anderson46President - Mitigation Resources (from March 2017)From prior to 2017 to February 2017, Environmental Manager, The Sabine Mining Company (an NACoal subsidiary).
Philip N. Berry54President - NAMining (from prior to 2017)
Eric A. Dale47Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017)
Carroll L. Dewing65Vice President - Operations of NACoal (from January 2017)
Andrew B. Hart43Controller of NACoal (from September 2019)From November 2017 to August 2019, Assistant Controller of NACoal. From prior to 2017 to October 2017, Assistant Controller at Rowan Companies, plc.
Brian M. Larson38President - Catapult Mineral Partners, LLC (from May 2019) and Director - Oil and Gas Development (from April 2019)From prior to 2017 to March 2019, Engineer at Pioneer Natural Resources.
J. Patrick Sullivan, Jr.


63 Vice President and Chief Financial Officer of NACoal (from prior to 2017)

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Item 1A. RISK FACTORS

The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect the Company’s business.

Risks related to the Coal Mining segment

Termination of or default under long-term mining contracts could adversely affect the Company's business, financial condition, results of operation and cash flows.

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure, including as discussed in “Item 1. Business — Business Developments" on page 2 or a result of GRE’s failure to complete the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy and its affiliates currently anticipated to close in the second quarter of 2022, could have a material adverse effect on the Company’s business, financial condition and results of operations.

State implementation of the EPA’s Regional Haze Rule (“RHR”) could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could, dependent on determinations by state regulatory commissions regarding approval to recover such costs from the customers of Coyote Creek’s customer, negatively impact Coyote Creek’s customers’ net income, financial position and cash flows. The Company understands that the North Dakota Department of Environmental Quality (“NDDEQ”) could require sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures. The emissions modeling conducted for the combined western state agencies affected by the RHR was delayed and has subsequently delayed the NDDEQ state implementation plan process. Therefore, the NDDEQ's state implementation plan, which was due to the EPA by July 2021, is anticipated to be submitted to EPA early in 2022. If NDDEQ requires significant emissions controls at Coyote Station power plant by December 31, 2028, it may not be economically feasible for Coyote Creek's customers to invest in such equipment and an early retirement of Coyote Station and the Coyote Creek mine could be necessary.

The Company could be negatively impacted by the decisions of Coyote Creek's customers. In September 2021, one of Coyote Creek's customers, Otter Tail Power Company, filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station power plant with an anticipated exit from the plant by December 31, 2028.

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

The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect the Company's business, financial condition, results of operation and cash flows.

For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of earnings of unconsolidated operations from two customers, Basin Electric and GRE. There are inherent risks whenever a significant percentage of total earnings are concentrated with a limited number of customers. Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of the Company's control. If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See “Item 1. Business — Business
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Developments" on page 2 in this Form 10-K for further discussion.

MLMC is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal fired generation, changes in customer demand and inflationary adjustments.

The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $136 million of long-lived assets, including property, plant and equipment and a coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.

MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

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

Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If any future lease payment is not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. A foreclosure of the Red Hills Power Plant could have a material adverse effect on MLMC's financial condition, results of operations and cash flows. Southern Company publicly disclosed that all required lease payments have been paid in full through December 31, 2021

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

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

The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.

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

Changes in coal consumption patterns of U.S. electric power generators could adversely affect the Company's profitability.

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

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

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

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

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

Government regulations could impose costly requirements on the Company and its customers.

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. The Company is required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.
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The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.

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

The Clean Air Act ("CAA") could reduce the demand for coal.

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has discussed issuing or issued regulations that impose tighter emission restrictions on a number of these compounds, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. A reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.

The Coal Mining segment's customers' operations require significant capital expenditures.

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

Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.

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

The Company faces numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Information concerning the Company's mining operations in "Item 2 - Properties on page 31" has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal in the Company's operational mines and other mining properties are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff and third parties, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals from the Company's mining properties and new mining or other data received.

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There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond the Company's control. Estimates of mineral reserves and resources necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

Geologic and mining conditions, including the Company's ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;
Demand for the Company's minerals;
Contractual arrangements, operating costs and capital expenditures;
Development and reclamation costs;
Mining technology and processing improvements;
The effects of regulation by governmental agencies;
The ability to obtain, maintain and renew all required permits;
Employee health and safety; and
NACCO's ability to convert all or any part of mineral resources to economically extractable mineral reserves.

As a result, actual tonnage recovered from identified mining properties and estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect the Company’s actual reserves and resources. Any material inaccuracy in estimates related to the Company's reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect the Company business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC’s property disclosure requirements for mining companies.

A defect in title or the loss of a leasehold interest in certain property could limit the Company's ability to mine coal reserves or result in significant unanticipated costs.

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

Risks related to the NAMining segment

The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.

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

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

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

The Company is subject to risks involved in the development of new mining projects.

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

NAMining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.

As of December 31, 2021, over 80% of the quarries NAMining operates are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for NAMining’s services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the NAMining business.

Risks related to the Minerals Management segment

The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.

The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. As discussed in “Item 1. Business — Business Developments" on page 2, the Company acquired additional mineral and royalty interests during 2021 and 2020 and plans to continue to pursue acquisitions of additional mineral and royalty interests. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company’s mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where the Company owns mineral and royalty interests, the Company’s lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments gives the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

Minerals are a depleting asset. Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company’s reserves and royalty income will decline.

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

Substantially all of the Minerals Management segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying the Company’s interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company’s control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

The Minerals Management segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Company's control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

Risks related to corporate structure

The Company’s stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.

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

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

The price of NACCO's securities may be volatile.

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

The amount and frequency of dividend payments made on NACCO's common stock could change.

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

NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

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

NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.

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

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

Certain members of the Company's extended founding family own a substantial amount of its Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.

The Company has two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2021, accounted for approximately 26 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2021, accounted for the remaining voting power of the Company. As of December 31, 2021, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 98 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 81 percent of the Company's total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.

General Risk Factors

The Company’s effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.
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The Company is subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in the Company’s effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.

Current and future capital and credit market conditions could adversely affect the Company’s ability to obtain bank financing on reasonable terms. Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in the Company’s ability to maintain financing at current levels.

The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. The Company’s wholly-owned subsidiary, NACoal, has a revolving line of credit of up to $150.0 million that expires in November 2025 (the "NACoal Facility"). The Company’s ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or obtaining a refinancing with terms that are not as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's operating results and financial condition.

Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.

Federal and state laws require the Company to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation and black lung benefits costs, leases and other obligations. Future federal and state laws and regulations may require higher amounts of financial security, including as a result of changes to certain factors used to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As the Company is required by state and federal law to have bonds or other acceptable security in place before mining can commence or continue, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the Company's financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on the Company’s liquidity and financial position. If the Company is unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase the Company’s costs and likely require greater use of alternative sources of funding for this purpose, which would reduce the Company’s liquidity.

Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in the Company’s ability to maintain insurance coverage at current levels.

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

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Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on the Company or expose the Company to new or additional risks.

Expectations relating to environmental, social and governance (“ESG”) matters have been rapidly evolving and increasing. Government organizations are enhancing or advancing legal and regulatory requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. The Company could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce the Company’s carbon footprint and promote sustainability. Investors may request the Company implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, the Company may face reputational challenges in the event its ESG practices are inconsistent with the third party views of acceptable ESG practices. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

The Company may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

The Company’s business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.

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

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

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

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

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

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

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

The Company’s results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies, such as the global outbreak of COVID-19.

The Company’s results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies, such as the global outbreak of COVID-19. The COVID-19 pandemic resulted in governments around the world implementing stringent measures to help control the spread of the virus. Although the Company has continued to operate facilities consistent with federal guidelines and state and local orders, the ongoing COVID-19 pandemic and the preventive or protective actions taken by governmental authorities may have a material adverse effect on the Company’s operations, work force, supply chain or customers, including business shutdowns or disruptions. The extent to which COVID-19 may adversely impact the Company's businesses depends on future developments, which are highly uncertain and unpredictable, including the extent of new outbreaks, the extent to which additional actions to mitigate the COVID-19 pandemic may be needed, the nature of government public health guidelines and the public's adherence to those guidelines. Any resulting financial impact cannot reasonably be estimated at this time, but could have a material adverse effect on the Company’s financial condition, cash flows and results of operations.

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

The Company’s operations could be disrupted by natural or human causes beyond its control.

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

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Item 1B. UNRESOLVED STAFF COMMENTS
None.

Item 2. PROPERTIES

Coal Mining Segment - Operations

NACCO-owned Resources and Reserves

1.0     INTRODUCTION

Information concerning the Company’s mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to the Company for the year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires the Company to disclose its mineral resources, in addition to its mineral reserves, both in the aggregate and for each of the Company’s individually material mining properties.

As used in this Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. Readers are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.

Readers are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have a too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, readers are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category. Likewise, readers are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See "Item 1A - “Risk Factors” on page 20.

The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRS’s”) prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS’s, incorporated herein by reference and made a part of this Report on Form 10-K.

TCoteau, Coyote Creek, Falkirk and MLMC, collectively referred to as “Mines subject to SEC Section 1300 reporting”, each wholly-owned subsidiaries of NACCO, operate surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. At each of these mines, the Company owns or controls the mineral resources and reserves.

The Company operates additional surface coal mines where the customer owns or controls the reserves. The Company conducts activities to extract these customer-owned reserves pursuant to long-term contracts.

Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During 2021 Subject to SEC Section 1300 reporting.

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nacco-20211231_g1.jpg

Figure 1.1 Surface Coal Mines Operational During 2021 Subject to SEC Section 1300 Reporting

At all Mines subject to SEC Section 1300 Reporting other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating cost, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates the Company's exposure to spot coal market price fluctuations.

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

A summary of coal production at the Mines subject to SEC Section 1300 Reporting for the past three years has been tabulated and is presented on Table 1.1 Production Summary.

Tons (in millions)
201920202021
The Coteau Properties Company13.512.612.5
The Falkirk Mining Company7.47.27.9
Coyote Creek Mining Company1.722
Mississippi Lignite Mining Company2.62.53
Totals25.224.325.4
Table 1.1 Production Summary
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2.0 MATERIAL MINING PROPERTIES

2.1 Freedom Mine — The Coteau Properties Company

The Freedom Mine generally produces between 12.5 million and 13.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale.

During 2020, Basin Electric informed 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. 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.

During August 2021, Bakken and Basin Electric signed a non-binding term sheet to purchase the assets of the Synfuels Plant. Bakken stated the closing date is expected to be April 1, 2023. As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close.

The Freedom Mine, operated by Coteau, is located approximately 90 miles northwest of Bismarck, North Dakota. The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 380 leases granting the right to mine approximately 34,016 acres of coal interests and the right to utilize approximately 23,455 acres of surface interests. In addition, Coteau owns in fee 33,805 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.

The reserves are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045 will be acquired as needed. No mineral processing occurs at the Freedom Mine.

2.2 Falkirk Mine — The Falkirk Mining Company

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually. The 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.

In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas. During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy and its affiliates. The closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.

The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83. Falkirk holds 335 leases granting the right to mine approximately 43,486 acres of coal interests and the right to utilize approximately 24,324 acres of surface interests. In addition, Falkirk owns in fee 40,666 acres of surface interests and 1,788 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

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The reserves are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coals in the reserve occur in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

There are no outstanding permits related to the life of mine ("LOM") plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. No mineral processing occurs at the Falkirk Mine.

2.3 Coyote Creek Mine - Coyote Creek Mining Company, LLC

The Coyote Creek Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 2016 to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. In September 2021, Otter Tail Power Company filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station power plant with an anticipated exit from the plant by December 31, 2028.

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

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

There are no outstanding permits related to the LOM plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. No mineral processing occurs at the Coyote Creek Mine.

2.4 Red Hills Mine — Mississippi Lignite Mining Company

The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant.

The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 7,343 acres of surface interest and 4,425 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,794 acres of coal interests and the right to utilize approximately 5,597 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,593 acres of coal interest. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations.The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 2032. No mineral processing occurs at the Red Hills Mine.
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3.0 MINERAL RESOURCES AND RESERVES

Mineral resources and reserves have been summarized from the TRS for each mine subject to SEC Section 1300 reporting and have been included as Table 3.1 and Table 3.2. Qualities are being reported on an as-received moisture basis except for sodium which is from the mineral analysis of ash.

SUMMARY MINERAL RESOURCES AS OF DECEMBER 31, 2021 BASED ON CUT-OFF GRADES OF
Coteau - $1.70/mmBTU, Falkirk - $2.60/mmBTU, Coyote - $2.27/mmBTU, and MLMC - $30.00/ton
Measured mineral resources
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
322,310,200
6,779
37.64
7.27
0.89
5.62
The Falkirk Mining Company
78,420,784
6,534
39.83
6.65
0.57
NA
Coyote Creek Mining Company
31,202,000
6,943
36.63
7.25
0.94
7.78
Mississippi Lignite Mining Company
11,475,500
5,110
44.0
14.1
0.60
NA
Total
443,408,484
6,704
38.12
7.34
0.83
5.81
Indicated mineral resources
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
8,188,400
6,776
37.92
7.22
0.90
6.36
The Falkirk Mining Company
199,721
6,317
37.10
10.69
0.73
NA
Coyote Creek Mining Company
3,905,900
6,942
36.55
7.39
0.97
7.70
Mississippi Lignite Mining Company
16,169,100
5,270
44.3
14.3
0.7
NA
Total
28,463,121
5,940
41.35
11.29
0.79
6.80
Measured + indicated mineral resources
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
330,498,600
6,778
37.64
7.27
0.89
5.63
The Falkirk Mining Company
78,620,505
6,534
39.82
6.66
0.57
NA
Coyote Creek Mining Company
35,107,900
6,943
36.62
7.26
0.94
7.77
Mississippi Lignite Mining Company
27,644,600
5,200
44.2
14.2
0.7
NA
Total
471,871,605
6,657
38.31
7.57
0.83
5.84
Inferred mineral resources
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
15,000
6,463
37.84
9.78
1.02
1.59
The Falkirk Mining Company
0
NA
NA
NA
NA
NA
Coyote Creek Mining Company
0
NA
NA
NA
NA
NA
Mississippi Lignite Mining Company
0
NA
NA
NA
NA
NA
Total
15,000
6,463
37.84
9.78
1.02
1.59
Table 3.1 Mineral Resources Summary



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SUMMARY MINERAL RESERVES AS OF DECEMBER 31, 2021 BASED ON CUT-OFF GRADES OF
Coteau - $1.55/mmBTU, Falkirk - $2.60/mmBTU, Coyote - $2.27/mmBTU, and MLMC - $28.04/ton
Proven mineral reserves
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
253,946,500
6,779
37.70
7.19
0.89
5.12
The Falkirk Mining Company
78,420,784
6,534
39.83
6.65
0.57
NA
Coyote Creek Mining Company
31,202,000
6,943
36.63
7.25
0.94
7.78
Mississippi Lignite Mining Company
17,167,900
5,070
43.5
15.0
0.6
NA
Total
380,737,184
6,665
38.31
7.44
0.82
5.41
Probable mineral reserves
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
3,552,300
6,756
38.29
6.78
0.84
5.40
The Falkirk Mining Company
199,721
6,317
37.10
10.69
0.73
NA
Coyote Creek Mining Company
3,905,900
6,942
36.55
7.39
0.97
7.70
Mississippi Lignite Mining Company
9,447,600
5,080
43.1
15.0
0.6
NA
Total
17,105,521
5,868
40.54
11.50
0.74
6.60
Total mineral reserves
Tonnage
Grades/qualities
Lignite Coal:
Calorific Value (Btu/lb)
Moisture (%wt)
Ash (%wt)
Sulfur (%wt)
Sodium (%wt)
The Coteau Properties Company
257,498,800
6,779
37.71
7.19
0.88
5.12
The Falkirk Mining Company
78,620,505
6,534
39.82
6.66
0.57
NA
Coyote Creek Mining Company
35,107,900
6,943
36.62
7.26
0.94
7.77
Mississippi Lignite Mining Company
26,615,500
5,070
43.4
15.0
0.6
NA
Total
397,842,705
6,631
38.41
7.61
0.81
5.44
Table 3.2 Mineral Reserves Summary

Internal Control Disclosure Over Mineral Resources and Reserves
The modeling and analysis of the Company’s resources and reserves has been developed by Company mine personnel and reviewed by several levels of internal management, including the QP, and in some instances, third parties. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QP, Company staff and in some instances, third parties. This section summarizes the internal control considerations for the Company’s development of estimations, including assumptions, used in resource and reserve analysis and modeling.

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QP and Company management agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QP.

Estimations and assumptions were developed independently for each significant mineral location. All estimates require a combination of historical data and key assumptions and parameters. When possible, resources and data from generally accepted industry sources, such as governmental resource agencies, were used to develop these estimations.

Geological modeling and mine planning efforts serve as a base assumption for resource estimates at each significant coal mining operation. These outputs have been prepared by both Company personnel and third parties, and the methodology is
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compared to industry best practices. Mine planning decisions are determined and agreed upon by Company management. Management adjusts forward-looking models by reference to historic mining results, including by reviewing actual versus predicted levels of production from the mineral deposit, and if necessary, re-evaluating mining methodologies if production outcomes were not realized as predicted. Ongoing mining of the mineral deposit, coupled with product quality validation pursuant to industry best practices and customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the mineral resource. Ongoing quality validation of production also provides a means to monitor for any potential changes in quality. Also, ongoing monitoring of ground conditions within the mine, surveying for evidence of subsidence and other visible signs of deterioration that may signal the need to re-evaluate rock mechanics and structure of the mine ultimately inform extraction ratios and mine design, which underpin mineral reserve estimates.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, identify hazards and inform operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

Customer-owned Resources and Reserves

South Hallsville No. 1 Mine — The Sabine Mining Company
The South Hallsville No. 1 Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began 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. The mine's reserves and resources are owned and controlled by AEP. The Company conducts activities to extract these customer-owned and controlled reserves.
During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.
The South Hallsville No. 1 Mine, operated by Sabine, is located approximately 150 miles east of Dallas, Texas on FM 968. The entrance to the mine is by means of a paved road. Sabine has no title, claim, lease or option to acquire any of the reserves at the South Hallsville No. 1 Mine. Southwestern Electric Power Company controls all of the reserves within the South Hallsville No. 1 Mine.
Five Forks Mine — Demery Resources Company, LLC
The Five Forks Mine generally produces between 0.1 million and 0.3 million tons of lignite annually. The mine began delivering coal in 2012 and is located approximately three miles north of Creston, Louisiana on State Highway 153. The mine's reserves and resources are owned and controlled by the customer. The Company conducts activities to extract these customer-owned and controlled reserves.
Access to the Five Forks Mine is by means of a paved road. Demery has no title, claim, lease or option to acquire any of the reserves at the Five Forks Mine. Demery's customer, Five Forks Mining, LLC, controls all of the reserves within the Five Forks Mine.
Facilities and Equipment
The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement.

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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, 2021 is set forth in the chart below:
LocationMining MethodTotal Historical Cost of Mine
Property, Plant and Equipment
(excluding Coal Land, Real Estate
and Construction in Progress), Net of
Applicable Accumulated
Amortization, Depreciation and Impairment
 
(in millions)
Unconsolidated Mining Operations 
Freedom Mine — The Coteau Properties CompanyDragline operation with 3 draglines$96.2 
Falkirk Mine — The Falkirk Mining CompanyDragline operation with 4 draglines$93.8 
South Hallsville No. 1 Mine — The Sabine Mining CompanyDragline operation with 4 draglines$59.3 
Five Forks Mine — Demery Resources Company, LLC
Truck-shovel operation (a)
$— 
Coyote Creek Mine — Coyote Creek Mining Company, LLCDragline operation with 1 dragline$131.7 
Consolidated Mining Operations
Red Hills Mine — Mississippi Lignite Mining CompanyDragline operation with 1 dragline$67.9 
OtherN/A$1.2 
(a) Predominantly all of Demery's machinery and equipment is owned by its customer.
NAMining Segment - Operations

NAMining provides contract mining services for independently owned mines and quarries, primarily operating and maintaining draglines at limestone quarries and utilizing other mining equipment at sand and gravel quarries. During 2021, NAMining operated 32 draglines and other equipment at 25 quarries. Of the 32 draglines, 9 are owned by the Company and 23 are owned by customers. At December 31, 2021, NAMining had $35.5 million in property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment.
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The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer. The following mines were operational during 2021:
Location NameAggregateLocationStateCustomerYear NACCO Started Operations
White Rock — NorthLimestoneMiamiFLWRQ1995
KromeLimestoneMiamiFLCemex2003
AlicoLimestoneFt. MyersFLCemex2004
FECLimestoneMiamiFLCemex2005
SCLLimestoneMiamiFLCemex2006
Card Sound LimestoneFlorida CityFLCemex2009
Central State AggregatesLimestoneZephyrhillsFLMcDonald Group2016
Mid Coast AggregatesLimestoneSumter CountyFLMcDonald Group2016
West Florida AggregatesLimestoneHernando CountyFLMcDonald Group2016
St. CatherineLimestoneSumter CountyFLCemex2016
Center HillLimestoneSumter CountyFLCemex2016
InglisLimestoneCrystal RiverFLCemex2016
Titan CorkscrewLimestoneFt. MyersFLTitan America2017
Palm Beach AggregatesLimestoneLoxahatcheeFLPalm Beach Aggregates2017
PerryLimestoneLamontFLMartin Marietta2018
SDI AggregatesLimestoneFlorida CityFLBlue Water Industries2018
QueensfieldSand and gravelKing William CountyVAKing William Sand and Gravel Company, Inc.2018
County Line (a)
LimestonePasco CountyFLK&M Pasco 130 Holdings, LLC2019
NewberryLimestoneAlachua CountyFLArgos USA, LLC 2019
Titan PennsucoLimestoneMiamiFLTitan America2020
Seven Diamonds LimestonePasco CountyFLSeven Diamonds, LLC2021
Johnson CountySand and gravelJohnson CountyINMartin Marietta2021
Little RiverSand and gravelAshdownARLehigh Hanson2021
RosserSand and gravelEnnisTXLehigh Hanson2021
Brooksville Cement PlantLimestoneBrooksvilleFLCemex2021
(a) The County Line contract was terminated during the third quarter of 2021. NAMining mined 0.1 million and 0.2 million tons of limestone at this location during the 2021 and 2020 periods, respectively.
NAMining's customers control all of the limestone and sand reserves within their respective mines. NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.
Access to the White Rock mine is by means of a paved road from 122nd Avenue.
Access to the Krome mine is by means of a paved road from Krome Avenue.
Access to the Alico mine is by means of a paved road from Alico Road.
Access to the FEC mine is by means of a paved road from NW 118th Avenue.
Access to the SCL mine is by means of a paved road from NW 137th Avenue.
Access to the Card Sound mine is by means of a paved road from SW 408th Street.
Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.
Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.
Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.
Access to the St. Catherine mine is by means of a paved road from County Road 673.
Access to the Center Hill mine is by means of a paved road from West Kings Highway.
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Access to the Inglis mine is by means of a paved road from Highway 19 South.
Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.
Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.
Access to the Perry mine is by means of paved road from Nutall Rise Road.
Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.
Access to the Queensfield Mine is by means of paved road from Dabney's Mill Road (SR 604).
Access to the County Line mine is by means of paved road from 18744 County Line Road.
Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).
Access to the Titan Pennsuco mine is by means of a paved road from NW 121st Way.
Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.
Access to the Johnson County mine is by means of a paved road from Old State 37/N Waverly Park Road.
Access to the Little River mine is by means of an unpaved road from Little River 60.
Access to the Rosser mine is by means of a paved road from TX-34 S.
Access to Brooksville Cement plant is by means of a paved road from Cement Plant Road.

Minerals Management - Operations

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 the Company’s estimate of the number of gross and net productive wells as of December 31, 2021:

GrossNet
Oil4670.9
Natural Gas39811.4
Total86512.3

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

Net wells are calculated based on the Company's net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.

The majority of the Company’s producing mineral and royalty interest acreage now, 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.

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The following table includes the Company's estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs as of December 31, 2021:

Gross Acres
Net Royalty Acres
Appalachia
34,66136,199
East Texas/Haynesville
6,4777,455
Permian
63,9981,243
Eagle Ford
15,5101,712
Other
7,13913,327
Total
127,78559,936

The Company may own more than one type of interest in the same tract of land, but the overlap is not significant. Net Royalty Acres are calculated based on the Company’s ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

The following table includes the Company's estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs as of December 31, 2021:

Developed AcreageUndeveloped AcreageGross Acreage
Appalachia28,0116,65034,661
East Texas/Haynesville5,2531,2246,477
Permian62,4961,50363,998
Eagle Ford15,510015,510
Other1,0216,1187,139
Total112,29115,495127,785

Undeveloped acres are either unleased and open or are leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Production and Price History

The following table sets forth the estimated oil and natural gas production data related to the Company’s mineral and royalty interests as well as certain price and cost information for the years ended December 31:

2021 (4)
2020
Production data:
Oil (bbl) (1)
32,627  2,239 
NGL (bbl) (1)
63,559  68,599 
Residue gas (Mcf) (2)
6,225,422  7,981,545 
Total BOE (3)
1,133,756  1,401,095 
Average realized prices:
Oil (bbl) (1)
$66.87  $36.27 
NGL (bbl) (1)
$29.33  $14.56 
Residue gas (Mcf) (2)
$3.36  $1.87 
Average unit cost
BOE (3)
$4.99 $6.01 
(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
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(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) BOE. Barrel of Oil Equivalent, a conversion factor of 6 MCF of gas was used for 1 equivalent bbl of oil.

(4) As an owner of mineral and royalty interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. As a result, the Company estimated the last two months of 2021 production and pricing data using projections based on decline rates of wells and prior expense information.

Evaluation and Review of Reserves

The reserves estimates as of December 31, 2021 were prepared by Haas Petroleum Engineering Services, Inc. ("Haas Engineering"). Haas Engineering has provided reservoir engineering services, consulting and ongoing support for major and independent petroleum companies, public utilities, financial institutions, investors, and government agencies since 1980. Haas Engineering does not own an interest in NACCO or any of the Company's properties, nor is it employed on a contingent basis. A copy of Haas Engineering's estimated proved reserve report as of December 31, 2021 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.

The properties evaluated are located in Alabama, Louisiana, Ohio, Pennsylvania, and Texas and represent all of the Company’s oil and gas reserves. A reserves audit is not the same as a financial audit. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs.

The reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate reserves in conformance with SEC regulations. The maximum remaining reserves life assigned to wells included in this report is 50 years.

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to the Company's interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of the Company’s reserves is a function of:

the quality and quantity of available data and the engineering and geological interpretation of that data;
estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;
future prices of oil, natural gas and NGLs, which may vary considerably from those estimated; and
the judgment of the persons preparing the estimates.

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The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31, 2021 based on the reserve report prepared by Haas Engineering, the Company’s independent petroleum engineering firm. All of the Company’s reserves are located in the United States.

Net reserves as of December 31, 2021
Oil (bbl) (1)
NGL (bbl) (1)
Residue gas (Mcf) (2)
Proved developed167,430 282,230 16,617,360 
Proved undeveloped220 90 1,210 
Total167,650 282,320 16,618,570 
(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Internal Control Disclosure

The Company's internal staff works closely with Haas Engineering to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to NACCO's assets. Internal technical team members met with independent reserve engineers periodically during the period covered by the reserves report to discuss the assumptions and methods used in the proved reserve estimation process.

The preparation of the Company's proved reserve estimates are completed in accordance with internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
Review and verification of historical production data, which data is based on actual production as reported by third-party producers who lease the Company’s royalty and mineral interests;
Preparation of reserve estimates by Haas Engineering under the direct supervision of internal staff;
Review by the President of Catapult Mineral Partners of all of the Company's reported proved reserves at the close of each quarter, including the review of all significant reserve changes;
Verification of property ownership by the Company's land department; and
No employee’s compensation is tied to the amount of reserves booked.

The Minerals Management Segment’s Business Operations Manager is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas Engineering in the preparation of the third-party reserve report. The Business Operations Manager has over 10 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests.

Headquarter locations

NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.

Coal Mining and Minerals Management lease corporate headquarters office space in Plano, Texas.
NAMining leases office and warehouse space in Medley, Florida.

Item 3. LEGAL PROCEEDINGS
Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

Item 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.
At December 31, 2021, there were 691 Class A common stockholders of record and 126 Class B common stockholders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Issuer Purchases of Equity Securities (1)
Period(a)
Total Number of Shares Purchased
(b)
Average Price Paid per Share
(c)
Total Number of Shares Purchased as Part of the Publicly Announced Program
(d)
Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program (1)
October 1 to 31, 2021— $— — $22,659,516 
November 1 to 30, 2021— $— — $22,659,516 
December 1 to 31, 2021— $— — $22,659,516 
     Total
— $— — $22,659,516 

(1)    On November 10, 2021, the Company's Board of Directors approved a stock purchase program ("2021 Stock Repurchase Program") providing for the purchase of up to $20.0 million of the Company’s outstanding Class A common stock through December 31, 2023. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

Item 6. SELECTED FINANCIAL DATA

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








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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
OVERVIEW
Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."

Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (“NACCO” or the “Company”). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. In addition, Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

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

See “Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.
The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.
Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers." See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's revenue recognition.
Long-lived assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
of the long-lived asset exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company recognized charges of $7.3 million in the Minerals Management segment and $1.1 million in the Coal Mining segment to write-off certain capitalized leasehold costs, prepaid royalties and other assets during 2020.
At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $136 million of long-lived assets, including property, plant and equipment and its coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.
Income taxes: Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.
The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.
Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position.
See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
CONSOLIDATED FINANCIAL SUMMARY

The results of operations for NACCO were as follows for the years ended December 31:
 20212020
Revenues:
   Coal Mining$91,851 $72,088 
   NAMining69,924 42,392 
   Minerals Management31,003 14,721 
   Unallocated Items4,695 2,133 
   Eliminations(5,627)(2,902)
Total revenue$191,846 $128,432 
Operating profit (loss):
   Coal Mining$49,059 $25,436 
   NAMining109 1,872 
   Minerals Management26,080 3,493 
   Unallocated Items(19,553)(17,256)
   Eliminations(285)(97)
Total operating profit$55,410 $13,448 
   Interest expense1,719 1,354 
   Interest income(449)(1,200)
   Closed mine obligations1,297 1,641 
   Gain on equity securities(3,423)(1,226)
   Other, net (584)(1,379)
Other income, net(1,440)(810)
Income before income tax provision (benefit)56,850 14,258 
Income tax provision (benefit)8,725 (535)
Net income $48,125 $14,793 
Effective income tax rate15.3 %(3.8)%

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

Other income, net

Interest income decreased $0.8 million primarily due lower interest rates and a lower average invested cash balance during 2021 compared with 2020.

Gain on equity securities represents changes in the market price of invested assets reported at fair value. The change in 2021 compared with 2020 was due to fluctuations in the market prices of the underlying assets. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's invested assets reported at fair value.

North American Coal Corporation India Private Limited ("NACC India") was formed to provide technical business advisory
services to the third-party owner of a coal mine in India. During 2014, NACC India's customer defaulted on its contractual
payment obligations and as a result of this default, NACC India terminated its contract with the customer and began pursuing
contractual remedies. During 2020, the Company received a $1.0 million payment from NACC India's customer which has been reported on the line, Other, net.

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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
Income Taxes

The Company recorded an income tax expense of $8.7 million for the year ended December 31, 2021 on income before income tax of $56.9 million, or 15.3%, compared to income tax benefit of $0.5 million for the year ended December 31, 2020 on income before income tax of $14.3 million, or (3.8%). The income tax benefit for the year ended December 31, 2020 included $7.3 million of discrete tax charges primarily related to settlement of tax examinations, reserves for uncertain tax positions and return to provision adjustments partially offset by a benefit of $4.7 million, primarily due to the rate differential related to carrying back losses under the provisions of the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act"). The CARES Act allows net operating tax losses incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company generated a net tax operating loss in 2020 primarily due to the realization of certain deferred tax assets. There were no material discrete items affecting income tax expense in 2021.

The effective income tax rate for 2021 reflects the impact of higher pre-tax income in 2021 compared with 2020, including the termination fee associated with the Bisti contract termination. The effective income tax rate varies based upon the mix and timing of earnings between entities that benefit from percentage depletion and those that do not benefit from percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

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

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows
The following tables detail the change in cash flow for the years ended December 31:
 20212020Change
Operating activities:   
Net income$48,125 $14,793 $33,332 
Depreciation, depletion and amortization23,085 18,114 4,971 
Deferred income taxes(3,553)7,517 (11,070)
Stock-based compensation5,561 3,078 2,483 
Gain on sale of assets(60)(269)209 
Inventory impairment charge 1,973 (1,973)
Other asset impairment charge 8,359 (8,359)
Other1,973 (3,452)5,425 
Working capital changes(256)(52,599)52,343 
Net cash provided by (used for) operating activities74,875 (2,486)77,361 
Investing activities:   
Expenditures for property, plant and equipment and acquisition of mineral interests(44,561)(44,368)(193)
Proceeds from the sale of assets633 571 62 
Other(219)(2,187)1,968 
Net cash used for investing activities (44,147)(45,984)1,837 
Cash flow before financing activities $30,728 $(48,470)$79,198 

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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
The $77.4 million increase in net cash provided by (used for) operating activities was primarily the result of favorable working capital changes and an increase in net income. Working capital changes primarily included:

Decreased payments made under deferred compensation and long-term incentive compensation plans in 2021 compared with 2020.
An increase in Accounts payable during 2021 compared with a decrease in Accounts payable during 2020 due to timing of payments.

 20212020Change
Financing activities:   
Net (reductions) additions to long-term debt and revolving credit agreements$(25,801)$20,073 $(45,874)
Cash dividends paid(5,617)(5,375)(242)
Other(1,755)(670)(1,085)
Net cash (used for) provided by financing activities $(33,173)$14,028 $(47,201)

The change in net cash (used for) provided by financing activities was primarily due to repayments during 2021 compared with borrowings during 2020.

Financing Activities
Financing arrangements are obtained and maintained at the subsidiary level. NACoal has a secured revolving line of credit of up to $150.0 million (the “NACoal Facility”) that expires in November 2025. Borrowings outstanding under the NACoal Facility were $4.0 million at December 31, 2021. At December 31, 2021, the excess availability under the NACoal Facility was $116.2 million, which reflects a reduction for outstanding letters of credit of $29.8 million.

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

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2021, for base rate and LIBOR loans were 1.25% and 2.25%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.35% on the unused commitment at December 31, 2021. During the year ended December 31, 2021, the average borrowing under the NACoal Facility was $20.5 million and the weighted-average annual interest rate was 2.1%.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to
EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2021, NACoal was in compliance with all financial covenants in the NACoal Facility.

The obligations under the NACoal Facility are guaranteed by certain of NACoal's direct and indirect, existing and future
domestic subsidiaries, and is secured by certain assets of NACoal and the guarantors, subject to customary exceptions and
limitations.

The Company believes funds available from cash on hand, the NACoal Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the NACoal Facility in November 2025.
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Expenditures for property, plant and equipment and mineral interests

Following is a table which summarizes actual and planned expenditures (in millions):
PlannedActualActual
 202220212020
NACCO$68.0 $44.6 $44.4 

Planned expenditures for 2022 are expected to be approximately $27 million in the NAMining segment, $22 million in the Coal Mining segment, $10 million in the Minerals Management segment and up to $9 million at Mitigation Resources.

In the Coal Mining segment, elevated levels of expected capital expenditures through 2022 are primarily related to spending at
MLMC as it develops a new mine area. In the NAMining segment, expected capital expenditures through 2022 are primarily
for the acquisition, relocation and refurbishment of draglines as well as the acquisition of other mining equipment to support the expansion of contract mining services beyond NAMining's historical dragline-oriented model, including the acquisition of
equipment to support Thacker Pass.

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

Capital Structure

NACCO's consolidated capital structure is presented below:
 December 31 
 20212020Change
Cash and cash equivalents$86,005 $88,450 $(2,445)
Other net tangible assets
276,733 244,907 31,826 
Intangible assets, net31,774 35,330 (3,556)
Net assets394,512 368,687 25,825 
Total debt(20,710)(46,465)25,755 
Closed mine obligations(21,686)(21,598)(88)
Total equity $352,116 $300,624 $51,492 
Debt to total capitalization 6 %13 %(7)%

The increase in other net tangible assets was primarily due to an increase in Property, plant and equipment including mineral interests and Other non-current assets at December 31, 2021 compared with December 31, 2020. The increase in Other non-current assets is primarily due to an increase in pension assets and deferred financing fees as well as an increase in the market price of invested assets reported at fair value.
Contractual Obligations, Contingent Liabilities and Commitments
Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company’s decisions to contribute above the minimum regulatory funding requirements. The Company does not expect to contribute to its pension plan in 2022. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.5 million per year from 2022 through 2031. Benefit payments beyond that time cannot currently be estimated. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2022 through 2031. Benefit payments beyond that time cannot currently be estimated. All other pension benefit payments are made from assets of the pension plan.
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
NACCO has leases. See Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's leases.
NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.
NACoal is a party to certain guarantees related to Coyote Creek. The Company believes that the likelihood of NACoal’s future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.
The Company utilizes letters of credit to support commitments made in the ordinary course of business. As of December 31, 2021 and 2020, outstanding letters of credit totaled $29.8 million and $3.0 million, respectively. The increase in outstanding letters of credit in 2021 is primarily due to the issuance of $20.0 million letters of credit to collateralize a portion of outstanding surety bonds used to guarantee performance of consolidated mine reclamation obligations.
ENVIRONMENTAL MATTERS
The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.
Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company’s policies stress environmental responsibility and compliance with these regulations. Based on current information, management does not expect compliance with these regulations to have a material adverse effect on the Company’s financial condition or results of operations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.

SEGMENT RESULTS

COAL MINING SEGMENT

FINANCIAL REVIEW
See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.
Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:
 20212020
Unconsolidated mines28,052 28,486 
Consolidated mines3,025 2,538 
Total tons delivered31,077 31,024 







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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
The results of operations for the Coal Mining segment were as follows for the years ended December 31:
 20212020
Revenues $91,851 $72,088 
Cost of sales 79,167 70,452 
Gross profit 12,684 1,636 
Earnings of unconsolidated operations(a)
56,982 56,584 
Contract termination settlement10,333 — 
Selling, general and administrative expenses27,363 30,216 
Amortization of intangible assets3,556 2,572 
Loss (gain) on sale of assets21 (4)
Operating profit $49,059 $25,436 
(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2021 Compared with 2020

Revenues increased 27.4% in 2021 compared with 2020 primarily due to an increase in customer demand and tons delivered at MLMC. Also contributing to the change was the recognition of reclamation revenue from Caddo Creek. During the fourth quarter of 2020, Caddo Creek entered into a contract with a subsidiary of Advanced Emissions Solutions to perform mine reclamation. As a result of these changes, Caddo Creek financial results are consolidated within the Coal Mining segment.

The following table identifies the components of change in operating profit for 2021 compared with 2020:
 Operating Profit
2020$25,436 
Increase (decrease) from: 
Contract termination settlement 10,333 
Gross profit, excluding MLMC's 2020 inventory impairment charge9,075 
MLMC 's inventory impairment charge during 20201,973 
Voluntary separation program ("VSP") charge during 20201,475 
Selling, general and administrative expenses, excluding VSP charge1,378 
Earnings of unconsolidated operations398 
Amortization of intangibles(984)
Net change on sale of assets(25)
2021$49,059 

Operating profit increased $23.6 million in 2021 compared with 2020. The change in operating profit was primarily due to:

The $10.3 million payment recognized during 2021 related to the Bisti contract termination.

An increase in gross profit due to an increase in the profit per ton delivered at MLMC and earnings associated with the reclamation contract at Caddo Creek. In addition, 2020 included certain costs associated with the termination of the Camino Real Fuels, LLC contract mining agreement and higher outside service expenses at Centennial Natural Resources.

The following items recognized in the prior year did not recur in 2021:

A $2.0 million inventory impairment charge at MLMC as mining costs exceeded net realizable value.
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
A charge of $1.5 million related to one-time termination benefits as a result of a voluntary separation program for employees who met certain age and service requirements to reduce overall headcount.
A $1.1 million asset impairment charge included in selling, general and administrative expenses in the table above.

In addition, selling, general and administrative expenses in 2021 include a decrease in employee-related costs and professional service expenses, both partially offset by higher insurance expense. Included in insurance expense is an increase of $1.3 million that is reimbursed by one of the Unconsolidated Subsidiaries. The offsetting income related to the reimbursement is included in Earnings of unconsolidated operations.

NORTH AMERICAN MINING ("NAMining") SEGMENT

FINANCIAL REVIEW
Aggregate tons delivered by the NAMining segment were as follows for the years ended December 31:
 20212020
Unconsolidated operations9,938 9,367 
Consolidated operations42,565 36,546 
Total tons delivered52,503 45,913 
The results of operations for the NAMining segment were as follows for the years ended December 31:
 20212020
Total revenues$69,924 $42,392 
Reimbursable costs51,028 26,893 
Revenues excluding reimbursable costs$18,896 $15,499 
Revenues $69,924 $42,392 
Cost of sales 67,078 39,266 
Gross profit 2,846 3,126 
Earnings of unconsolidated operations(a)
3,861 3,619 
Selling, general and administrative expenses6,610 5,138 
Gain on sale of assets(12)(265)
Operating profit $109 $1,872 
(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2021 Compared with 2020

Total revenues increased 64.9% in 2021 compared with 2020 primarily due to a $24.1 million increase in reimbursable costs, which have an offsetting amount in cost of sales and have no impact on operating profit. The relocation of draglines related to new and amended contracts is the main driver of the increase in reimbursable costs. The increase in revenues excluding reimbursable costs is primarily due to an increase in customer demand and tons delivered.





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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
The following table identifies the components of change in operating profit for 2021 compared with 2020.
 Operating Profit
2020$1,872 
Increase (decrease) from: 
Selling, general and administrative expenses(1,472)
Gross profit(280)
Net change on sale of assets(253)
Earnings of unconsolidated operations242 
2021$109 

Operating profit decreased $1.8 million in 2021 compared with 2020 primarily due to an increase in selling, general and administrative expenses, mainly attributable to higher employee-related costs, which include an increase in business development expenses.

MINERALS MANAGEMENT SEGMENT
FINANCIAL REVIEW
The results of operations for the Minerals Management segment were as follows for the years ended December 31:
 20212020
Revenues $31,003 $14,721 
Cost of sales 2,988 2,342 
Gross profit 28,015 12,379 
Selling, general and administrative expenses2,004 8,886 
Gain on sale of assets(69)— 
Operating profit $26,080 $3,493 
2021 Compared with 2020

Revenues and operating profit increased in 2021 compared with 2020 primarily due to royalty income generated by gas production from the Ohio and Louisiana mineral interests, as well as oil production from the Permian Basin and Eagle Ford Shale mineral interests acquired late in the fourth quarter of 2020 and early in the second quarter of 2021, respectively. Favorable changes in natural gas and oil prices also contributed to the improvement in revenues and operating profit. In addition, the Company recognized $3.6 million of settlement income during 2021.

The decrease in selling, general and administrative expenses is primarily due to the absence of a $7.3 million asset impairment charge recognized in 2020. The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company wrote-off certain capitalized leasehold costs and prepaid royalties related to legacy coal interests in 2020.

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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)
UNALLOCATED ITEMS AND ELIMINATIONS

FINANCIAL REVIEW
Unallocated Items and Eliminations were as follows for the years ended December 31:
 20212020
Operating loss$(19,838)$(17,353)
2021 Compared with 2020

The operating loss increased during 2021 compared with 2020 primarily due to higher employee-related costs and an increase in expenses related to business development initiatives.

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

NACCO Industries, Inc. Outlook

Coal Mining Outlook

As previously announced, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy. The closing of this sale is expected to occur in the second quarter of 2022. Upon completion of the sale of Coal Creek Station, the existing agreements between GRE and Falkirk will terminate. GRE will pay the Company $14.0 million, as well as transfer ownership of an office building and convey membership units in Midwest AgEnergy to wholly owned and consolidated subsidiaries of NACCO.

Upon closing of the sale to Rainbow Energy, a new Coal Sales Agreement ("CSA") between Falkirk and Rainbow Energy will become effective and Falkirk will continue supplying all coal requirements of Coal Creek Station. Falkirk will be paid a management fee per ton of coal delivered for operating the mine, and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances.

Coal Mining operating profit in 2022 is expected to decrease significantly compared with 2021. This expected decrease is primarily the result of a decrease in coal deliveries from 2021 levels, as well as the termination of the Bisti contract. An anticipated increase in operating expenses primarily due to expected higher insurance costs and other professional fees is also expected to contribute to the reduction in operating profit.

Results at the consolidated mining operations are expected to decrease significantly in 2022 from 2021 primarily due to expected substantially lower earnings at MLMC driven by an anticipated reduction in customer demand from 2021 levels, which contributes to an increase in the cost per ton. Cost inflation on repairs, supplies and diesel fuel, and higher depreciation expense related to recent capital expenditures to develop a new mine area will also contribute to the increase in the cost per ton in 2022. In general, cost per ton delivered is lowest when the power plant requires a consistently high level of coal deliveries, primarily because costs are spread over more tons.

The reduction in earnings at the unconsolidated Coal Mining operations is expected to be mainly driven by lower earnings at Falkirk resulting in part from a planned power plant outage prior to the expected closure of the Rainbow Energy transaction. In addition, to support the transfer of Coal Creek Station, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA with Rainbow Energy through May 31, 2024. After May 31, 2024, Falkirk's per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)




which tracks a broad measure of U.S. inflation. Termination of the Bisti contract in late 2021 will also contribute to a decline in the earnings at the unconsolidated mining operations in 2022.

Segment adjusted EBITDA, which excludes the termination payments of $10.3 million from Bisti's customer in 2021 and the anticipated $14 million contract termination fee from GRE in 2022, is expected to decrease significantly in 2022 from 2021 primarily as a result of the forecasted reduction in operating profit partially offset by an increase in depreciation, depletion and amortization expense. The increase in depreciation, depletion and amortization expense is primarily due to higher capital expenditures at MLMC as a result of the development of a new mine area.

Capital expenditures are expected to be approximately $22 million in 2022. The elevated levels of capital expenditures from 2019 through 2022 relate to the necessary development of a new mine area at MLMC, which will allow continued coal deliveries through the end of the contract. The increase in capital expenditures associated with mine development will result in higher depreciation expense in future periods that will unfavorably affect future operating profit. Capital expenditures for MLMC are expected to decline significantly beginning in 2023.

The Company's contract structure at each of its coal mining operations eliminates exposure to spot coal market price fluctuations. However, fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. The significant increase in natural gas prices in 2021 contributed to an increase in customer power plant dispatch and coal deliveries in 2021 over 2020. Sustained higher natural gas prices could lead to increased demand for coal and positively affect the Coal Mining segment results in 2022. Changes to expectations for customer power plant dispatch could affect the Company’s outlook for 2022 and over the longer term. The owner of the power plant served by the Company's Sabine Mine in Texas intends to retire the power plant in the first quarter of 2023, at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of the customer. Coteau operates the Freedom Mine in North Dakota. All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative. Basin Electric utilizes the coal at the Great Plains Synfuels Plant, Antelope Valley Station and Leland Olds Station. The Synfuels Plant is a coal gasification plant owned by Dakota Gas that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide and other chemical products for sale. In August 2021, Basin Electric announced that it signed a non-binding term sheet which contemplates the sale of the assets of Dakota Gas. As part of the announcement, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with the potential buyer does not close.

NAMining Outlook

In 2022, NAMining expects full-year operating profit to increase significantly over 2021 due to an expected increase in customer requirements and contributions from contracts executed during 2021. Segment adjusted EBITDA for 2022 is expected to increase significantly compared with the prior year as a result of the improvement in operating profit and an increase in depreciation expense.

During 2021, NAMining expanded its geographic footprint by entering into new contract mining services agreements at quarries in Indiana, Texas and Arkansas. In addition, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida. Presently, NAMining is operating two smaller draglines at this quarry while it relocates a larger dragline that will significantly increase production capacity once commissioned, which is expected to occur in the second half of 2022. NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida. NAMining continues to have a substantial pipeline of potential new projects and is pursuing a number of growth initiatives that, if successful, would be accretive to future earnings.

In 2019, NAMining's subsidiary, Sawtooth Mining, LLC, entered into a mining services agreement to serve as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada, owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium produced. In January 2022, Lithium Americas provided an update on the Thacker Pass project, which noted that final permitting decisions are expected to be received in the first quarter of 2022. Early-works construction is expected to begin in 2022. At maturity, this management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.
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Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





In 2022, capital expenditures are expected to be approximately $27 million primarily for the acquisition, relocation and refurbishment of draglines, as well as the acquisition of other mining equipment to support the continued expansion of contract-mining services beyond NAMining's historical dragline-oriented model, including the acquisition of equipment to support the Thacker Pass lithium project. The cost of mining equipment related to Thacker Pass will be reimbursed by the customer over a seven-year period from the equipment acquisition date.

Minerals Management Outlook

The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil, natural gas liquids and coal, extracted primarily by third parties.

Operating profit and Segment adjusted EBITDA in 2022 are expected to decrease significantly from 2021 primarily driven by an anticipated reduction in production due to the natural decline curve on wells in Ohio, expectations for natural gas and oil prices, and the absence of $3.6 million of settlement income recognized in 2021. The Company expects oil and gas market prices to moderate in 2022 and stabilize at levels consistent with averages over the second half of 2021.

Natural gas and oil benchmark prices increased during 2021 when compared with historical periods. If natural gas and oil prices remain at higher levels than currently anticipated, results for the 2022 full year could be favorably impacted. Commodity prices are inherently volatile and as an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its interests is limited. The Company's expectations are based on the best information currently available and could vary as a result of adjustments made by operators and/or changes to commodity prices.

The Company is in a period of transition where production from more recently acquired mineral interests is expected to begin to offset anticipated declines in production at legacy natural gas wells. This transition is expected to occur over the next few years as the Company’s portfolio of recently acquired mineral interests continues to expand. Minerals Management is targeting additional investments in mineral and royalty interests of approximately $10 million in 2022. These investments are expected to be accretive, but each investment's contribution to earnings is dependent on the details of that investment, including the size and type of interests acquired and the stage and timing of mineral development. The contribution of each investment could also vary due to commodity price changes. These acquired interests are expected to align with the Company’s strategy of selectively acquiring mineral and royalty interests with a balance of near-term cash-flow yields and long-term growth potential, in high-quality reservoirs offering diversification from the Company’s legacy mineral interests.

Consolidated Outlook

Overall, in 2022, NACCO expects consolidated net income and Consolidated Adjusted EBITDA to decrease significantly from 2021. Lower operating profit in the Coal Mining segment and an anticipated reduction in income in the Minerals Management segment are expected to be partially offset by higher operating profit at NAMining and lower income tax expense. Additionally, the Company expects to recognize the value of the North Dakota office building and the membership units in Midwest AgEnergy, which are expected to be received as part of the compensation from GRE upon the closing of the transaction with Rainbow Energy. Securing contracts for new mining projects and acquisitions of additional mineral interests could be accretive to the current forecast.

Consolidated capital expenditures are expected to be