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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, 2024

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)

| Delaware |  | 34-1505819 |
| (State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.) |
| 22901 Millcreek Blvd, | Suite 600 |  |  |
| Cleveland, | Ohio |  |  |  | 44122 |
| (Address of principal executive offices) |  | (Zip Code) |

Registrant's telephone number, including area code: (440) 229-5151
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 share |  | NC |  | New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: Class B Common Stock, $1 par value per share. 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 filer | ☐ | Accelerated filer | ☑ | Non-accelerated filer | ☐ | Smaller reporting company | ☑ | Emerging 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. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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, 2024 (the last business day of the registrant's most recently completed second fiscal quarter): $117,744,151
Number of shares of Class A Common Stock outstanding at February 28, 2025: 5,866,937
Number of shares of Class B Common Stock outstanding at February 28, 2025: 1,565,359
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Proxy Statement for its 2025 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.

NACCO INDUSTRIES, INC.
TABLE OF CONTENTS

|  |  | PAGE
PART I. |  |  |
| Item 1. | BUSINESS | 1
| Item 1A. | RISK FACTORS | 18
| Item 1B. | UNRESOLVED STAFF COMMENTS | 27
| Item 1C. | CYBERSECURITY | 28
| Item 2. | PROPERTIES | 29
| Item 3. | LEGAL PROCEEDINGS | 48
| Item 4. | MINE SAFETY DISCLOSURES | 48
PART II. |  |  |
| Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | 49
| Item 6. | [RESERVED] | 49
| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 50
| Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 64
| Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 64
| Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 64
| Item 9A. | CONTROLS AND PROCEDURES | 64
| Item 9B. | OTHER INFORMATION | 64
| Item 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | 64
PART III. |  |  |
| Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | 65
| Item 11. | EXECUTIVE COMPENSATION | 65
| Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | 65
| Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | 65
| Item 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES | 65
PART IV. |  |  |
| Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | 66
| Item 16. | FORM 10-K SUMMARY | 71
SIGNATURES | 72
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | F-1

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PART I
Item 1. BUSINESS
General
NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources and with NACCO collectively, the Company, we, our or us), bring natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate 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. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (Catapult) business, acquires and promotes the development of mineral interests. Mitigation Resources of North America® (Mitigation Resources) provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services. In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.
We have items not directly attributable to a reportable segment that are not included in the reported financial results of the operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, and the financial results of Bellaire Corporation (Bellaire), Mitigation Resources, ReGen Resources and other developing businesses. Bellaire manages our 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
NACCO’s portfolio of businesses operate under the umbrella of NACCO Natural Resources. Management continues to view our long-term business outlook positively. Our businesses provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and chemicals. Increasing demand for electricity, on-shoring and current federal policies are creating favorable macroeconomic trends within these industries. Management is confident in our trajectory and business prospects as well as longer-term growth opportunities.
While we realize the coal mining industry continues to face challenges, we believe the current political environment may change the sentiment surrounding fossil fuel industry-related regulations. These developments are expected to further support coal as an essential part of the energy mix in the United States for the foreseeable future.
NAMining is our primary platform for growth around mining activities. With a focus on operational excellence, scalability and driving profitable growth, NAMining expects to improve operating margins as well as achieve additional growth through its ongoing business development activities. New contracts and contract extensions are central to the business' organic growth strategy. The goal is to continue NAMining's ongoing expansion as a leading provider of contract mining services for customers who produce a wide variety of minerals and materials, and we expect NAMining to be a substantial contributor to operating profit over time.
The Minerals Management segment, through our Catapult business, has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests in the United States that is expected to deliver near-term cash flow yields and long-term growth. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids, typically net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The current portfolio provides a strong foundation of well-positioned assets that are expected to continue to deliver solid financial results. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the full cost of exploration, production and/or development. We intend to continue these activities, while at the same time evaluating investments in non-operated working interests that we believe can reliably increase cash flow and enhance overall returns. As a non-operator, we seek to diversify our investment and operational risk through participation in oil and gas wells with multiple operators across multiple basins. While the timing of returns could vary, we maintain a long-term perspective and believes the Minerals Management segment will provide unlevered after-tax returns on invested capital in the mid-teens as the business matures.
Mitigation Resources, which provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services, continues to build on the substantial foundation it has established over the past several years. Our Mitigation Resources business offers an opportunity for growth and diversification in an industry where we have a strong
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reputation as well as substantial knowledge and expertise. In addition, Mitigation Resources is providing ecological restoration services for abandoned surface mines and was named a designated provider of abandoned mine land restoration by the State of Texas. Mitigation Resources is working to develop a protected habitat for toads in Texas, as well as pursuing additional environmental restoration projects. We believe that Mitigation Resources can provide solid rates of return on capital employed as this business matures. As of December 31, 2024, we have 11 mitigation banks and other mitigation projects located in Alabama, Florida, Georgia, Mississippi, Pennsylvania, Tennessee and Texas.
We believe our businesses have competitive advantages that provide value to customers and continuing to invest in our businesses can create long-term value for stockholders. We have strategically leveraged our core mining and natural resources management skills to build a robust portfolio of affiliated businesses and opportunities for additional growth remain strong. Acquisitions of additional mineral interests and improvements in the outlook for Coal Mining segment customers, as well as new contracts at Mitigation Resources and NAMining and development of other business opportunities should be accretive to our longer-term outlook.
NACCO also continues to pursue activities which can strengthen the resiliency of our existing coal mining operations. We remain 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 our 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, weather and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants.
We continue to look for ways to create additional value by utilizing our core mining competencies, which include reclamation and permitting. NACCO established ReGen Resources to utilize these skills to address the rapidly increasing demand for additional power generation sources in the United States through development of energy-related projects that utilize multiple generation technologies, such as solar combined with gas-fired generation, primarily on reclaimed mining properties. These projects could be developed by ReGen Resources directly or through joint ventures that include partners with expertise in energy development projects and their financing. Current opportunities in development include solar arrays, solar-gas hybrid projects and carbon capture on reclaimed mine land in Mississippi and Texas, as well as early-stage review of projects in other states.
NACCO is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. We believe strategic diversification will generate cash that can be re-invested to strengthen and expand our businesses. We also continue to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.
Business Developments
Coal Mining Segment
During 2023, Mississippi Lignite Mining Company (MLMC) received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed MLMC's long-lived assets for impairment and recorded a $65.9 million impairment charge in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.
The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas. All production from Sabine was delivered to
Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American
Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.
NAMining Segment
Sawtooth Mining, LLC (Sawtooth) will be the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada. Thacker Pass is owned by a joint venture between Lithium Americas Corp. (TSX: LAC) (NYSE: LAC) and General Motors Holdings LLC. Thacker Pass commenced construction in 2023 and is targeting initial production in 2027. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services,
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Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.
During 2024 and 2023, NAMining amended and extended existing limestone contracts with two customers and expanded the scope of work with several other customers. New contracts signed in 2024 are expected to be accretive to earnings starting in 2026.
Minerals Management Segment
During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of
2024, in Eiger, LLC (Eiger), which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.
During 2023, Minerals Management acquired $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin.
Other Items
In December 2023, we entered into a power purchase agreement with the Tennessee Valley Authority (TVA) for the energy generated from a proposed 67.5 MW solar photovoltaic electric generation facility to be developed on reclaimed land at our Red Hills Mine. The development of this project is subject to the favorable completion of an Environmental Assessment under the National Environmental Policy Act (NEPA) and approval of an interconnection agreement with TVA. In addition, we entered into an engineering, procurement and construction agreement related to the interconnection of the project during 2025. The estimated commercial operation date for this generation facility is late 2027.
Operations
Coal Mining Segment
The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with our customer's operations.
As of December 31, 2024, the Coal Mining segment's operating coal mines were: The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and MLMC. Each of these mines supply lignite coal for power generation and delivers our coal production to an adjacent power plant or synfuels plant under a long-term supply contract. While MLMC’s coal supply contract contains a take or pay provision, the contract contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party; all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.
The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our 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's customer operates the Red Hills Power Plant, which supplies electricity to TVA under a long-term power purchase agreement. MLMC’s contract with its customer runs through April 1, 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC.
At Coteau, Coyote Creek and Falkirk, we are 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. Our customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing 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 us. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.
Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity (VIE). In each case, NACCO
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is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our 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 our 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 our consolidated U.S. tax return; therefore, the Income tax benefit line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.
We perform contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, our 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.
See Item 2. Properties on page 29 in this Form 10-K for discussion of our mineral resources and mineral reserves.
NAMining Segment
The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for our growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for our customers by performing the mining aspects of our customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of December 31, 2024, NAMining operates in Florida, Texas, Arkansas, Virginia and Nebraska.
In addition, Sawtooth will supply all of the lithium-bearing ore requirements for Thacker Pass, which is currently in the development stage with construction activities underway. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services, Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.
Minerals Management Segment
The Minerals Management segment derives income primarily by leasing our 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 Minerals Management segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests (collectively mineral and 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 royalty interests may be calculated net of post-production expenses, and typically have no environmental liability. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.
•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. The NPRI owner does; however, typically receive royalty payments.
•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
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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.
We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own 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 does not currently have any material investments under which it would be required to bear the cost of exploration, production or development. The Minerals Management segment will benefit from the continued development of our mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired as the capital costs or lease operating expenses are born entirely by the operators or working interest owners.
During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of
2024, in Eiger, which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. This entity meets the definition of a VIE. NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, this contract is accounted for as an equity method investment. During 2024, we recorded $0.6 million, which represented our share of earnings, as Earnings of unconsolidated operations on the Consolidated Statements of Operations. Our investment is reported on the line Equity method investment in Eiger, LLC in the Consolidated Balance Sheets. Due to a lag in Eiger's financial reporting, earnings or losses from this investment will be recorded on a one quarter lag.
Excluding the Eiger investment described above, total consideration for the acquisitions of mineral and royalty interests was $0.7 million and $36.7 million, in 2024 and 2023, respectively. The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres. The 2023 acquisitions included 43.4 thousand gross acres and 2.5 thousand net royalty acres.
We also manage legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of our legacy reserves were acquired as part of our historical coal mining operations.
Total oil and gas mineral and royalty interests include approximately 198.4 thousand gross acres and 63.9 thousand net royalty acres at December 31, 2024. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8 th royalty lease, and assumes a 1/4 th royalty rate for unleased acres.
See Item 2. Properties on page 29 in this Form 10-K for discussion of our proved reserves.
Customers
The principal customers of the Coal Mining segment are electric utilities and an independent power provider.
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 mineral owner, we have 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, including price, on which such volumes are marketed and sold.
In 2024 and 2023, three customers and two customers, respectively, accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:
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|  |  | Percentage of Consolidated Revenues
| Segment |  | 2024 |  | 2023 |  |
| Coal Mining customer |  | 29 | % |  | 40 | % |  |
| NAMining customer |  | 24 | % |  | 22 | % |  |
| NAMining customer |  | 11 | % |  | 7 | % |  |

The loss of any of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on our consolidated results of operations.
Competition
Coteau, Coyote Creek, Falkirk and MLMC each have only one customer for which they extract and deliver coal. Our coal mines are directly adjacent to our 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 pricing of renewable energy and our 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 develop our reserves will depend upon the interaction of these factors.
Coal-fired 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 displace coal-fired electric baseload power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal. Fluctuations in natural gas prices and the availability of renewable energy sources, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Over the longer term, we continue to believe that customer demand will remain pressured by regulations mandating or incentivizing the purchase of power from subsidized renewable energy sources, particularly wind and solar. See Item 1. Business — Government Regulation on page 9 in this Form 10-K for further discussion. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.
Based on industry information, we believe we were one of the ten largest coal producers in the U.S. in 2024 based on total coal tons produced.
NACCO believes that we were the largest dragline operator in the U.S. in 2024.
NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.
In the Minerals Management segment, the oil and gas industry is intensely competitive; we primarily compete 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 our 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 we can, which would adversely affect our 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 our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business
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conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Seasonality
We have experienced limited variability in our 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 our 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. In addition, demand for coal-fired power generation can increase due to unusually hot or cold weather as consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for coal-fired power generation.
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, significant weather events, 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 our 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, our lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices during the first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations. Due to these seasonal fluctuations, Minerals Management results of operations for individual quarterly periods may not be indicative of the results that may be realize on an annual basis.
Human Capital
As of December 31, 2024, we had approximately 1,700 employees, including approximately 1,100 employees at our unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes we have good relations with our employees.
Market-Based Compensation: We believe our employees are critical to our success and we invest in our 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. We offer a 100% 401(k) matching contribution up to 5% of compensation, which is immediately vested. Additionally, NACCO offers a generous profit-sharing contribution for all of our full-time and part-time employees. We provide 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 employees, spouses and dependents;
•Flexible spending accounts for both healthcare and dependent care;
•Health savings accounts and health reimbursement accounts, both of which receive company contributions;
•Paid vacation and holidays;
•Parental leave;
•Short-term and long-term disability benefits;
•Wellness incentives for employees;
•Life and AD&D insurance benefits;
•Identity protection benefits;
•Charitable donation matches; and
•Employee assistance program.
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Employee Development: We recognize that our culture and success is strengthened when employees are respected, motivated and engaged. We work to match employees with assignments that capitalize on the skills, talents and potential of each employee, and provides opportunities for professional growth. NACCO believes training is a critical component of employee well-being and growth. Training ranges from equipment-specific task training and enhanced safety procedures to strategic leadership and management training, ethics training and role-specific training. Employees are encouraged to pursue continued professional development, skills training and other educational opportunities. Qualified employees are eligible to participate in a tuition reimbursement program to advance their formal education. We believe 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.
Safety: Employee safety in the workplace is one of our core values. We are committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. The National Mining Association ranks NACCO as an industry leader in safety, and our incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data. We have earned more than 100 safety awards at the state and national levels since the 1980s. NACCO strives to have zero safety incidents or injuries. Our operations have onsite safety personnel who train employees in safe work practices, review safety-related incidents and recommend improvements when appropriate. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. We believe 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. Every employee is responsible and accountable for safety performance.
Company Ethics: We have processes in place for compliance with our Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of our Directors and employees annually complete certifications with respect to compliance with our Code of Corporate Conduct. In addition, all of our employees are required to complete annual Code of Corporate Conduct training. The Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy require employees to comply with applicable laws and regulations, maintain high ethical standards and report situations of actual or potential noncompliance. All NACCO personnel are required to report without delay any conduct which they believe to be illegal or a violation of our policies. The identity of any NACCO personnel making such a report is kept in strict confidence except as required by law, and we utilize a third-party hotline to ensure reports can be generated anonymously. Retaliation in any form against an individual who exercises their right to make a complaint in good faith is strictly prohibited.
Community Engagement: We value our local communities and provide support through volunteer activities, financial contributions and well-paying jobs. NACCO believes in making long-term investments in the areas where we operate by supporting numerous charitable efforts, including educational, arts and community organizations. Community engagement is encouraged and supported through our matching gift program. We will match employee contributions up to $5,000 per employee if program criteria are met.
Please visit nacco.com/stewardship/ for the full text of certain NACCO stewardship policies.
Available Information
We make our 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 through our 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 our 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 our website is intended to be an inactive textual reference only. The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding us and other issuers that file electronically with the SEC.
Under Rule 12b-2 of the Exchange Act, we qualify as a smaller reporting company because our public float as of the last business day of our most recently completed second quarter was less than $250 million. For as long as we remain a smaller reporting company, we 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.
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Government Regulation
Our 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 our Coal Mining segment.
Numerous federal, state and local governmental permits and approvals are required for coal mining operations. Our subsidiaries hold or will hold the necessary permits at all of our lignite coal mining operations. At the coal mining operations where our subsidiaries hold the permits, we are 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.
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 Minerals Management segment.
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
Our 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. We have 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.
The election of Donald Trump, paired with Republican control of Congress, is likely to have a significant and favorable impact on the regulatory environment, particularly for fossil fuels. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed.
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.
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SMCRA establishes operational, reclamation and closure standards for surface coal mines. We accrue for the costs of final mine closure, including the cost of treating mine water discharges, at mines where our subsidiaries hold the mining permit. While these obligations are largely unfunded, they can require securitization through bonding, 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 Office of Surface Mining Reclamation and Enforcement (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.
Greenhouse Gas (GHG) Emissions
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 (NOx), mercury, particulates and other matter. Federal and 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 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.
In May 2024, the EPA published the final rules for GHG emissions and Mercury Air Toxics Standards (MATS) in the Federal Register. The final MATS and GHG rules will require compliance as early as 2027 and 2032, respectively.
Previous efforts by the EPA were met with extensive litigation and there has been a similar response to the new GHG and MATS rules. State coalitions have filed lawsuits challenging both of these rules. Several other entities, including electric generators and industry groups, have joined the lawsuits. In July 2024 and October 2024, stay motions for the GHG and MATS rules were denied by the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit Court), respectively. Following the D.C. Circuit Court denial, emergency stay motions were filed for the GHG and MATS rules with the Supreme Court of the United States (SCOTUS). In October 2024, the SCOTUS denied the stay applications for the GHG and MATS rules. The GHG and MATS cases continue through the normal procedures in the D.C. Circuit Court without stays in place. On February 19, 2025, the D.C. Circuit granted an EPA motion to hold the GHG case in abeyance for 60 days while the new EPA evaluates its position on the GHG rule. Similarly, on February 20, 2025, the D.C. Circuit granted an EPA motion to hold the MATS case in abeyance and removing the case from the upcoming oral argument calendar while the new EPA evaluates its position on the MATS rule. We cannot predict the full impact of the MATS and GHG rules on the operations of the coal-fired generation facilities operated by our customers; however, if the rules go into effect, the additional compliance costs could have a material adverse effect on our Coal Mining segment.
The GHG standards are based on technologies such as carbon capture and sequestration/storage and natural gas co-firing. The compliance deadline for existing coal-fired, steam generating electric generating units (EGUs) planning to install carbon capture and sequestration/storage technology has been extended to January 1, 2032 for plants that intend to operate beyond 2039. If a coal-fired plant intends to close prior to 2032, no controls will be required and if a plant plans to close between 2032 and 2039, they must begin co-firing with natural gas by January 1, 2030.
The MATS rules finalize changes for the filterable particulate matter surrogate emission standard for non-mercury metal hazardous air pollutants for existing coal-fired EGUs, the filterable particulate matter emission standard compliance demonstration requirements, and the mercury emission standard for lignite-fired EGUs. Review of the MATS rules indicate that the EPA significantly reduced the fine particulate matter emission standard for all existing coal-fired EGUs and will require continuous monitoring equipment to demonstrate compliance. Furthermore, the EPA elected to remove the lignite subcategory for mercury limits and will require lignite-fired EGUs to meet the same standard as other types of coal.
The recent change in presidential administrations, recent executive actions, and the resulting changes at the EPA make it unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed. The various parties are working through the legal and administrative processes and the actual outcome remains unknown at this time.
The CAA requires the EPA to review national ambient air quality standards (NAAQS) every five years to determine whether revisions to current standards are appropriate. In addition, 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 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
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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 affect 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. Our 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. On May 6, 2024, the EPA lowered the level for particulate matter by 25%. States are required to update their state implementation plans by February 2027. The rule is currently being challenged at the D.C. Circuit by a coalition of states led by Kentucky and West Virginia. Oral argument was held at the D.C. Circuit on December 16, 2024.
In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address interstate transport of pollutants. While the CSAPR affects states in the eastern half of the U.S. and Texas, it does not affect EGUs in North Dakota. 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.
In 2019, certain states submitted SIPs to the EPA in response to the 2015 ozone standard reduction. On February 13, 2023, the EPA rejected the SIPs. The EPA’s action to deny the SIPs was challenged in various courts, including the 5th Circuit Court of Appeals (the Fifth Circuit). The Fifth Circuit issued a stay of the SIP rejection in Texas, Louisiana, and Mississippi which prevents the federal implementation plan (FIP) from going into effect pending the outcome of the litigation challenges.
On June 5, 2023, the EPA published the FIP in the Federal Register. The FIP decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stay beginning in 2024 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. On July 31, 2023, the EPA promulgated an interim rule (Interim FIP) that addresses the various judicial orders where the SIP rejection has been stayed. The Interim FIP requires these states to return to the previously approved NOx trading program and emission caps. The Interim FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the power plants in these states under the Group 2 trading program.
In June 2024, the SCOTUS decided to stay the rule pending further review on the merits because the EPA's justifications were flawed. The Ozone Transport Rule was premised on its applicability to 23 states, but litigation resulted in the removal of 12 of those states that accounted for over 70 percent of the emissions the EPA had planned to address. The EPA purported to select control measures that would maximize cost effectiveness in achieving downwind ozone air quality improvements, but it did so based on an assumption that all 23 states would apply the uniform levels of controls required by the FIP. The case was remanded to the D.C. Circuit where the parties fully briefed the case. Subsequent to briefing, the EPA asked to partially remand the rule to "take a supplemental final action addressing the record deficiency preliminarily identified by the Supreme Court." The EPA finalized the supplemental response in December 2024. On February 6, 2025, the EPA filed a motion requesting abeyance of litigation for 60 days to allow a transition to the new administration. On February 21, 2025, the D.C. Circuit denied the EPA's request to hold the litigation in abeyance and extending the briefing schedule through March 27, 2025.
Should the FIP be fully implemented in states where a stay has been issued, the rule could influence the closure of some coal-fired EGUs that have not installed selective catalytic reduction technologies, potentially including the EGU supplied by MLMC. We cannot predict the outcome of the legal challenges to the: (i) various state challenges; (ii) the FIP promulgated on June 5, 2023; (iii) the interim final rule promulgated on July 31, 2023; nor (iv) the supplemental response dated December 10, 2024 that seeks to address the judicial orders. If the original FIP withstands legal challenge, it would increase the cost of operating the customer facility serviced by MLMC.
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. State implementation of the EPA’s Regional Haze Rule could require our North Dakota customers to incur significant new costs at their respective power plants, which could result in the premature closure of such power plants and their associated mines. The North Dakota Department of Environmental Quality (NDDEQ) finalized its state implementation plan and submitted it to the EPA for approval in August 2022. The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at the North Dakota power plants. In July 2024, the EPA issued a proposed partial denial of the state implementation plan. We submitted comments to the EPA on the proposed partial denial during the third quarter of 2024 and have filed a petition for review with the Eight Circuit Court of Appeals. The State of North Dakota, several of our customers, and others have also filed petitions for review. On February 27, 2025, the EPA filed an unopposed motion to hold these consolidated cases in abeyance for 120 days while the new administration evaluates its position on the partial denial of the state implementation plan. Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be
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economically feasible for our North Dakota customers to invest in such equipment, which could result in early retirement of our customers' power plants and our associated mines.
Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. These new rules may raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive, and/or result in early closure of the coal-fired EGU's operated by our customers which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of our coal mines. We cannot predict the full impact of the various GHG and CAA rules on the operations of the coal-fired EGUs operated by our customers and any early closure of our mines could have a material adverse effect on our business, financial condition and results of operations.
The Trump administration is expected to direct the EPA to reconsider and revise or rescind the EPA’s rules regulating emissions from power plants, among other regulatory actions affecting power generation, and has already issued executive orders aimed at this outcome. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. Although we anticipate the EPA’s review of such regulations likely will result in less stringent requirements, we cannot predict the outcome of any final EPA actions or court challenges to such final actions.
Clean Water Act
CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for wastewater
discharge, including from coal mines.
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 (WOTUS.) On May 25, 2023, the SCOTUS issued its Sackett vs. EPA ruling that defined WOTUS as “a relatively permanent body of water connected to traditional interstate navigable waters” with a “continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.” As a result of the Sackett decision, the EPA and the Army Corps of Engineers authored a revised definition of WOTUS and promulgated a final rule. The new rule does not go into effect in states where a stay had been issued for the previous rule, including North Dakota, Texas, Louisiana, and Mississippi. In these states, the legal challenges to this rule have resumed. In the meantime, securing CWA permits may be more challenging since the agencies in the states where a stay has been issued have less guidance to rely on to determine whether certain features are considered WOTUS. To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our coal mining operations.
Bellaire is treating mine water drainage from coal refuse piles associated with former underground coal mines in Ohio and 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. In 2004, Bellaire was notified by the Pennsylvania Department of Environmental Protection that it was required to establish a mine water treatment trust to serve as a long-term funding mechanism related to this obligation. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.
These federal and state requirements could require more costly water treatment and could materially adversely affect our business, financial condition and results of operations.
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 2020, the EPA finalized changes to the coal combustion residual (CCR) rule that classified all clay-lined surface impoundments that receive CCR as unlined. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of disposal capacity with a deadline to initiate closure and a new site-specific alternative due to permanent cessation of coal-fired boilers with deadlines to complete closure.
In May 2023, the EPA published proposed regulations that would impose federal regulatory requirements for previously
exempt inactive CCR surface impoundments at inactive facilities (legacy CCR surface impoundments). In May 2024, the EPA published a final rule amending CCR regulations which introduces new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired power plants with a legacy surface impoundment. The regulations impose new requirements including groundwater monitoring, closure standards, post-closure care obligations, and potential remediation activities.
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These rules 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 and ultimately result in the early closure of the mines servicing these plants, including closure of our mines. Any such closure of our mines could have a material adverse effect on our business, financial condition and results of operations.
In compliance with these regulations, Falkirk's customer, the owner of the Coal Creek Station power plant, submitted a CCR Part B application to the EPA in 2020 asserting a unit complied with the CCR rules. In the first quarter of 2023, the EPA proposed to deny the owner’s application. The owner and other parties have submitted additional information and comments supporting the owner’s position. If the EPA ultimately denies the owner’s application, a new liner may need to be installed or new waste management processes and/or units may need to be constructed. Accordingly, it is possible that a denial by the EPA could require a temporary unit shut down. Any temporary unit shut down could result in a temporary suspension of operations at Coal Creek Station. To minimize any impact to operations, Coal Creek Station continues to work with the EPA and is moving forward with plans to dry CCR materials produced by the plant, reducing the need to utilize the lined area in question. Falkirk is the sole supplier of lignite coal to Coal Creek Station. Any suspension of operations at Coal Creek Station would eliminate the need for lignite coal during the suspension period. Any such suspension of operations at Coal Creek Station or any of the power plants supplied by our mines could have a material adverse effect on our business, financial condition and results of operations.
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, we provide the required
information to the appropriate federal agency to enable it to complete the required study. Historically, this process has been
lengthy and may take several years to complete. In January 2023, the White House Council on Environmental Quality (CEQ)
issued interim guidance that instructs federal agencies to quantify GHG emissions and use the social cost of greenhouse gases to calculate a monetary metric associated with the proposed actions’ climate effects. The NEPA and interim guidance could adversely affect our ability to secure necessary permits.
On June 3, 2023, President Biden signed the Fiscal Responsibility Act of 2023 into law, which included certain provisions
collectively known as the Builder Act. The Builder Act includes amendments to NEPA which codify past regulatory reforms,
including narrowing what qualifies as a major federal action, limiting the scope of NEPA review to “reasonably foreseeable
environmental effects,” narrowing consideration of cumulative effects, directing agencies to only consider technically and
economically feasible reasonable alternatives and providing page limits and timelines for environmental impact statements and
environmental assessments. In April 2024, the CEQ finalized the revised NEPA rules.
On February 16, 2025, CEQ issued a notice that it intends to rescind all CEQ NEPA implementing regulations. These actions have raised significant questions regarding how CEQ’s NEPA regulations and agency-specific NEPA procedures will be interpreted and enforced going forward. We are unable to predict what impact the new CEQ guidance will have on our ability to obtain governmental permits.
Federal Coal Leasing
We enter into leases of Federally owned coal for a small portion of the coal mined at certain of our North Dakota mines. In July 2024, the Department of Interior’s Bureau of Land Management (BLM) published its North Dakota Proposed Resource Management Plan (RMP), which provided that no Federal coal which lies more than four miles away from a currently existing surface coal mining permit will be available for future leasing in North Dakota. In September 2024, the Company, along with other stakeholders, including the Governor of North Dakota, filed protests against the RMP. The BLM denied the protests and published the final RMP in January 2025. The State of North Dakota filed a challenge to the RMP in the United States District Court for the District of North Dakota on February 25, 2025. We are currently evaluating a similar challenge. If any such challenges are not successful, we may be required to alter our mine plans to avoid areas of Federal coal in the future.
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, 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 us any differently or to any greater or lesser extent than they affect other companies in the industry with similar assets.
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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 or 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. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids (NGLs) are not currently regulated and are made at market prices.
Environmental Matters
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our 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 our 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.
In December 2023, EPA finalized a rule that will require oil and gas producers to reduce methane and other air pollutants from existing sources. Oil and gas companies will be required to phase out routine flaring of natural gas and install methane leak detection equipment. 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.
In May 2024, the EPA finalized a rule containing revisions and additions to the New Source Performance Standards (NSPS) program rules (the Final Methane Rule). The Final Methane Rule formally reinstates emission limitations on methane, a GHG emission, for existing and modified facilities in the oil and gas sector. Specifically, the Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. Several states and industry groups have filed suit before the D.C. Circuit challenging the Final Methane Rule. On October 4, 2024, the SCOTUS denied applications for an immediate stay of the Final Methane Rule pending review by the D.C. Circuit Court of Appeals. Though the final outcome is uncertain, the rule establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources. The Final Methane Rule could have a significant impact on the upstream and midstream oil and gas sectors.
In November 2024, the EPA announced a final rule to reduce methane emissions from the oil and gas sector. The rule requires payment of a Waste Emissions Charge (WEC) on waste emissions of methane from certain oil and gas facilities. The Inflation Reduction Act-mandated fee would be triggered when companies report more than 25 metric tons of carbon dioxide equivalent per year to the EPA's Greenhouse Gas Reporting Program. The fee begins at $900 per metric ton of methane exceeding that threshold in 2024 and increases over time. A petition for review was filed in January 2025 by a coalition of Texas-led states and other industry groups. The fee could have a significant impact on the upstream and midstream oil and gas sectors.
Drilling and Production
The operations of the Minerals Management segment’s third-party lessees and our equity method investee 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
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wells, drilling bonds and generating reports concerning operations. The states, and some counties and municipalities, in which we have 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;
•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 our 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 our 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 our mineral interests, negatively affect the economics of production from these wells or limit the number of locations operators can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our 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.
On January 20, 2025, President Trump issued several executive orders that prioritized energy security, exploration and production on federal lands and processing of Liquefied Natural Gas export applications. Implementation of these executive orders could positively impact domestic drilling and production of oil and natural gas.
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.
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
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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 our mineral interests, including those held by our equity method investee, 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 our 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 our mineral interests or our equity method investment.
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 our 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 we hold 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 we hold mineral interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.
Natural Gas Sales and Transportation
Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which 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, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on natural gas-related activities.
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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, we believe that the regulation of oil transportation rates will not affect our 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, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as they are to our competitors.
State Regulation
States regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. 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 we 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 and to limit the number of drilled wells or locations of our third-party lessee operators or of our equity method investment.
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. We do not believe that compliance with these laws will have a material adverse effect on our results of operations or financial condition.
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. We 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, we have 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, we may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect our 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 we are required to conduct our operations.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2025 the name, age, current position and principal occupation and employment during the past five years of our executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.
EXECUTIVE OFFICERS OF THE COMPANY

Name |  | Age |  | Current Position |
J.C. Butler, Jr. |  | 64 |  | President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACCO Natural Resources Corporation (NNRC) (from prior to 2019) |
Elizabeth I. Loveman |  | 55 |  |  | Senior Vice President and Controller and Principal Financial Officer (from prior to 2019) |
John D. Neumann |  | 49 |  |  | Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to 2019) |
Thomas A. Maxwell |  | 47 |  |  | Senior Vice President - Financial Planning and Analysis and Treasurer (from prior to 2019) |

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name |  | Age |  | Current Position |
J.C. Butler, Jr. |  | 64 |  | President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NNRC (from prior to 2019) |
Carroll L. Dewing |  | 68 |  | Senior Vice President and Chief Operating Officer of NNRC (from prior to 2019) |
John D. Neumann |  | 49 |  |  | Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to 2019) |
J. Patrick Sullivan, Jr. |  | 66 |  |  | Senior Vice President and Chief Financial Officer of NNRC (from prior to 2019) |

Item 1A. RISK FACTORS
We operate 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 our business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business.
Risks related to the Coal Mining segment
Termination of or default under long-term mining contracts could adversely affect our 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 we have 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 or contract default could have a material adverse effect on our business, financial condition and results of operations.
The coal mining industry is subject to ongoing complex governmental regulations and legislation that could adversely impact our long-term mining contracts and our results of operations, liquidity, financial condition and cash flow.
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. We are 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
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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 our mining operations, cost structure or customers. All of these factors could significantly reduce our profitability.
Congress has considered climate change legislation aimed at reducing GHG emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions at the federal or state level, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups of coal-fired power plants, could result in electric generators switching from coal to other fuel sources or premature facility closures.
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 energy sources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, certain governmental agencies provide 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 potential impact on us 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 require electricity generators to diminish their reliance on coal as a fuel source. Complicating these matters further, over the last several decades, U.S. Administrations have increasingly relied on regulations and executive orders to implement environmental policies and objectives in the absence of Congressional agreement regarding new legislation. This condition, which creates instability and unpredictability of environmental regulations, seems likely to persist and could increase due to apparent polarization between the two main political parties. As a result, we and/or our customers, often must comply with and otherwise adapt to environmental regulations without assurance of their continued effect. We and/or our customers often do not have the ability to anticipate, or prepare in advance for, changes in regulatory approaches that may be implemented following a change in Administration. The SCOTUS’s recent decision in Loper Bright Enterprises v. Raimondo overturned the SCOTUS’s longstanding deferral to the applicable agency’s interpretation of ambiguous federal laws. We are unable to predict whether, or to what extent, this decision will alter the outcome of judicial reviews of current or future regulations. We do not know whether risks related to current and future regulations affecting us will be significantly mitigated by the decision in Loper Bright.
In view of the significant uncertainty surrounding each of these factors, it is not possible for us to predict reasonably the impact that any such laws, regulations or other policies may have on our business, financial condition and results of operations. However, such impacts could have a material adverse effect on our business, financial condition and results of operations.
See Item 1. Business — Government Regulation on page 9 in this Form 10-K for discussion of regulations that could materially adversely affect the Coal Mining segment.
The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect our business, financial condition, results of operation and cash flows.
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 our 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 our 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 we are unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, our business, financial condition, results of operations and cash flows could be adversely affected. See Item 1. Business — Business Developments on page 2 in this Form 10-K for further discussion.
MLMC is subject to risks associated with our 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, adverse mining conditions and growing competition from alternative power generation that competes with coal-fired generation. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs or decreased revenues could materially reduce our profitability.
Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established
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indices over time. 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 inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.
Diesel fuel is heavily weighted among the indices used to determine the coal sales price. The diesel fuel-related component of the coal sales price is based on average price changes over time whereas the impact on actual costs from changes in diesel fuel prices is more immediate; therefore, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.
Any reduction in customer demand at MLMC, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the customer's Red Hills Power Plant, economic conditions, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.
The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.
The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a management fee approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the Unconsolidated Subsidiaries' customers pay us our 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, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the Coal Mining segment's customers' facilities, economic conditions and governmental regulations could have a material adverse effect on our 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 our profitability.
Changes in coal consumption patterns of U.S. electric power generators could adversely affect our 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 us. 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 have the most potential to continue to displace a significant amount of coal-fired electric power generation. 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.
Any of these risks could result in a decrease in coal consumption by our customers and could have a material adverse effect on our business, financial condition and results of operations.
We are subject to burdensome federal and state mining regulations and the assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.
Federal and state statutes require us to restore mine property in accordance with specified standards and an approved reclamation plan, and require that we obtain and periodically renew permits for mining operations. Regulations require us to incur the cost of reclaiming current mine disturbance at operations where we hold the mining permit. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our 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 our business and could significantly reduce our profitability.
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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 Mining 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.
We face 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 our mining operations in Item 2 - Properties on page 29 has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. 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 at MLMC are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff, 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, new mining or other data received.
There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond our control. While we believe that our mineral reserve and resource estimates are developed using well-established practices and with appropriate controls, mineral reserve and mineral resource estimation is an imprecise and subjective process. Estimates of mineral reserves and resources 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 our 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 our minerals;
•Contractual arrangements, operating costs and capital expenditures;
•Development and reclamation costs;
•Mining technology and processing improvements;
•The effects of regulation by governmental agencies, including volatility in the political, legal and regulatory environments due to the U.S. presidential administration;
•The ability to obtain, maintain and renew all required permits;
•Employee health and safety; and
•Our ability to convert all or any part of mineral resources to economically extractable mineral reserves.
As a result, actual tonnage recovered, estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves and resources. Any material inaccuracy in estimates related to our 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 our 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 our ability to mine coal reserves or result in significant unanticipated costs.
We conduct a significant part of our 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. We may not verify title to leased properties or associated coal reserves until we are committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend 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, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and/or pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
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Risks related to the NAMining segment
We have experienced growth in our NAMining business in recent periods and we may not be able to sustain growth or manage future growth effectively.
We have expanded our overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as we scale the NAMining business. We must effectively integrate, develop and motivate employees, while integrating new equipment and customers in an efficient and effective manner. We anticipate 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 we are unable to manage this growth and the associated expenses effectively, we may not be able to take advantage of market opportunities or remain competitive. We may also fail to execute on our 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.
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 our 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.
We are subject to risks involved in the development of new mining projects.
From time to time, we seek 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 or reductions in making capital expenditures by NAMining's customers, timely regulatory approvals, 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 our 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, 2024, over 75% 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 occurr ence 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
We have no control over the timing of the development and operation of our natural gas, oil and coal reserves extracted by third parties.
We own mineral and royalty interests in the continental United States. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development. We primarily derive income from royalty-based leases under which lessees make payments to us based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on our mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by us, and depends on a number of factors outside of our control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, our 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 we own mineral and royalty interests, our 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 our royalty payments or continue operations. A failure on the part of the lessee to make royalty payments may give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. However, we may not be able to find a replacement lessee or might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if we are able to enter into a new
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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 our expected royalty income and profitability.
Minerals are a depleting asset. Unless we replace existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, our 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 our third-party lessees conduct successful ongoing well development activities or we continually acquire mineral and royalty interests, production and income related to our 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 our current and future mineral and royalty interests. These operators may not have access to the capital needed to develop our mineral interests. We 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 we use 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 our expected royalty income and 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 our interests are sold. Prices of oil and natural gas are volatile due to factors beyond our 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, including if energy supply exceeds demand; market uncertainty and a variety of additional factors that are beyond our control; market expectations about future prices of oil and natural gas; the level of 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 ongoing conflicts in foreign nations and associated oil and natural gas import bans as well as 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; volatility in the political, legal and regulatory environments due to the U.S. presidential election; 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.
The marketability of oil and natural gas production is dependent upon transportation, pipelines and refining facilities and continued operation of the U.S. power grid. Any limitation in the availability of these items could interfere with our third-party lessee’s ability to market oil and natural gas production and may adversely affect the Minerals Management segment’s financial condition or results of operations.
The marketability of our third-party lessee’s production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties as well as continued reliable operation of the U.S power grid. Any significant disruption in the U.S. power grid, gathering system or transportation, processing, or refining-facility capacity could reduce our third-party lessee’s ability to market oil production and may adversely affect the Minerals Management segment’s financial condition or results of operations.
Risks related to long-term growth strategy
Our investments in mitigation solutions, comprehensive reclamation and restoration construction services as well as solar and other energy-related development projects are subject to substantial risks and uncertainties.
There are risks associated with NACCO's ability to execute on our longer term growth strategy, including our investment in mitigation solutions, comprehensive reclamation and restoration construction services as well as clean energy projects through our Mitigation Resources of North America and ReGen Resources businesses, and our ability to develop and manage such projects profitably. These include political and regulatory developments that may make it more costly, or impossible, to pursue these business opportunities, logistical risks and potential delays related to construction, permitting and regulatory approvals; operational risk that the projects will not perform according to expectations; weather conditions or other factors beyond our
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control. All of the aforementioned risks could reduce the viability of project development. We have and will continue to incur costs in connection with these projects and the results of operations and/or return on investment could be negative or lower than anticipated and we may need to write-down the value of capitalized assets associated with these projects. Furthermore, our ability to forecast results may be hindered or inaccurate and the projects may not perform as predicted. Even if these projects are profitable in the long term, they may not be profitable in the short term, and results of operations are unlikely to be even quarter over quarter.
In addition, our investments in solar and other energy projects are dependent, in part, upon current state regulatory incentives and federal tax credits in order for the projects to be economically viable. These projects face the risk that the current state regulatory programs and tax laws may expire or be adversely modified and could have a material adverse effect on our operating results and financial condition.
Risks related to corporate structure
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 our 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.
The price of NACCO's securities may be volatile.
The price of our 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 our quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism; (v) announcements concerning NACCO, our customers or 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 our common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in our common stock may not be able to resell their stock at or above the price they paid or at all. Further, we 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 our operating results.
NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to NACCO's stockholders. Provisions in our 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 our common stock and may have the effect of delaying or preventing a change in control.
Our stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.
Our 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 our management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for our Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require us 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 our Class A common stock. The existence of a stock repurchase program could cause the price of our 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 our Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of our Class A common stock may decline below the levels at which we 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 us to repurchase any dollar amount or number of shares of our 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 our Class A common stock to decline.
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NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.
We are 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 our performance with other public companies.
NACCO cannot predict whether investors will find our common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for our common stock and the stock price may be more volatile.
Certain members of our extended founding family own a substantial amount of our 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.
We have 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, 2024, accounted for approximately 27 percent of our voting power. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2024, accounted for our remaining voting power. As of December 31, 2024, certain members of our extended founding family held approximately 36 percent of our outstanding Class A common stock and approximately 99 percent of our outstanding Class B common stock. On the basis of this common stock ownership, certain members of our extended founding family could have exercised approximately 82 percent of our 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 our certificate of incorporation and our sale or the sale of our assets. Because certain members of our extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, we may be a less attractive takeover target, which could adversely affect the market price of our common stock.
General Risk Factors
Our effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.
We are 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 our 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 our 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 our ability to maintain financing at current levels.
We may be unable to obtain financing on reasonable terms. Historically, we have addressed our 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. Our wholly-owned subsidiary has a revolving line of credit of up to $200.0 million that expires in September 2028. Our 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 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 refinance with terms that are as favorable as the existing terms of such indebtedness, could have a material adverse effect on our 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 us 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 benefit costs, leases, transmission interconnection construction costs, power purchase agreement delivery obligations and other obligations. Future federal and state laws and regulations, regional transmission organizations and power purchase agreement customers may require higher amounts of financial security, including as a result of changes to certain factors used
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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 we are required by state and federal law to have bonds or other acceptable security in place before mining can commence or for certain projects to move forward, 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 our financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand other forms of collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on our liquidity and financial position. If we are 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 our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our 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 our ability to maintain insurance coverage at current levels.
We hold a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because we are involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure us in the future. In addition, if we make significant insurance claims under our insurance policies, such claims may have a material adverse effect on our 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 our liability insurance coverage limits, could have a material adverse effect on our operating results and financial condition.
Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on us or expose us to new or additional risks.
Expectations relating to environmental, social and governance (ESG) matters have been rapidly evolving. Government organizations are enhancing or advancing legal, regulatory and disclosure 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. We could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. Investors may request that we 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, we may face reputational challenges in the event our ESG practices are inconsistent with the third-party views of acceptable ESG practices. Further, there is an increasing number of state-level anti-ESG initiatives in the United States that may conflict with other regulatory requirements or various stakeholders’ expectations. 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.
We 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. 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 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.
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Our business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if we experience a security breach, a cyber incident or cyber attack.
Like many other companies, we are 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 our, 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 we 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 our 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 our reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.
We rely on information technology systems to operate our 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 operations. Despite our efforts, our 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 our business operations, we collect and store confidential information from our customers and vendors and personal information and other confidential information from our employees. Although we have 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 our or our 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 our ability to respond appropriately.
We 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 our operations, damage our reputation, and expose us to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on our 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 our activities could impact the business. We are continuously installing new and upgrading existing information technology systems. We use employee awareness training around phishing, malware, and other cyber risks. We believe these incidents are likely to continue and are unable to predict the direct or indirect impact of future attacks or breaches to business operations.
Our operations could be disrupted by natural or human causes beyond our control.
Our operations are subject to disruption from natural or human causes beyond our 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, any of which could result in suspension of operations or harm to people or the environment. While all of our operations are located in the United States, we participate in a global supply chain, and if governments regulate or restrict the flow of labor or products or impede the travel of our personnel, our ability to conduct normal business operations could be impacted which could adversely affect our results of operations and liquidity.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
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Item 1C. CYBERSECURITY
Cybersecurity continues to be a key governance priority for us. NACCO maintains a cybersecurity program that is aligned with our business and has established policies and processes for assessing, identifying, and managing material risk from cybersecurity threats, which have been integrated into our overall risk management processes and governance structure.
We have implemented and invested in, and will continue to implement and invest in, controls, technologies, and resources (both internal and external) that are designed to identify, protect against, detect, respond to and mitigate cybersecurity risks, in alignment with frameworks established by the National Institute of Standards and Technology. These include, but are not limited to, internal reporting mechanisms, monitoring and detection tools, threat intelligence, and general and role-based training. NACCO's commitment to cybersecurity emphasizes cultivating a security-minded culture through education and training that reflect best practices and improved cybersecurity awareness. We also maintain third party management processes to identify and manage the cybersecurity risks associated with third party service providers. We periodically evaluate our cybersecurity program internally and by engaging with consultants to conduct reviews and assessments of the program. Such reviews and assessments may include penetration testing, maturity assessments as well as table-top and other exercises with subsequent remediation of key findings. Additionally, we have a Cybersecurity Task Force in place that is comprised of individuals across various departments within our organization including information systems, legal, finance, human resources and internal audit which meets regularly to further advance our cybersecurity strategy.
Our Board of Directors (Board) oversees NACCO's risk management. Our full Board regularly reviews information provided by management to oversee risk identification, risk management and risk mitigation strategies. The Audit Review Committee assists the Board with cybersecurity risk oversight. The Audit Review Committee is responsible for regularly reviewing and discussing with management risk exposure relating to cybersecurity, which includes reviewing the state of our cybersecurity program and emerging cybersecurity developments and threats, as well as the steps management has taken to monitor and mitigate such exposure. In 2024, our Board and the Audit Review Committee received periodic updates throughout the year on cybersecurity matters and these updates are part of their standing agendas.
Our Chief Information Security Officer (CISO) leads NACCO's cybersecurity program and is responsible for the management of our cybersecurity risks. The CISO has extensive cybersecurity knowledge and skills gained from over 30 years of technical and business experience, including as General Manager & President of MLMC, Vice President of Mississippi Operations and Vice President of Innovation & Technology. The CISO holds a bachelor’s degree in engineering, an executive MBA, and certifications in cybersecurity from Harvard. Additionally, the CISO successfully completed an Executive course through Northwestern’s Kellogg School of Management focused on artificial intelligence during 2024. The CISO reports directly to the President and Chief Executive Officer. The CISO manages a team of internal and external resources that have expertise and experience in cybersecurity. The CISO is informed of cybersecurity incidents by the cybersecurity team, which is generally responsible for monitoring the prevention, detection, mitigation, and remediation of cybersecurity incidents. We have an established process governing our assessment, response and internal and external notifications upon the occurrence of a cybersecurity incident, including evaluation of the potential impacts of cybersecurity incidents to determine materiality. Depending on the nature and severity of an incident, this process provides for escalation procedures upon discovery of material cybersecurity risks, including notification to our executive management and/or Board.
As of the date of this filing, our business strategy, results of operations, and financial condition have not been materially impacted as a result of any previously identified cybersecurity incidents; however, NACCO cannot provide assurance that we will not be materially impacted in the future by such risks or any future material incidents. For additional information regarding our cybersecurity risks, please refer to Item 1A - Risk Factors on page 18.
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Item 2. PROPERTIES
Coal Mining Segment - Operations
NACCO-owned Properties
1.0 INTRODUCTION
Information concerning our mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. 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 subpart 1300 of Regulation S-K.
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 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 18.
The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summary (TRS) prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. The TRS was prepared by certain of our employees. 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, incorporated herein by reference and made a part of this Report on Form 10-K. The information regarding MLMC was reviewed by our employees that are qualified persons as defined by subpart 1300 of Regulation S-K.
Coteau, Falkirk, Coyote Creek and MLMC, 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.
Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During 2024 Subject to SEC Section 1300 Reporting.
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Figure 1.1 Surface Coal Mines Operational During 2024 Subject to SEC Section 1300 Reporting
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)
| 2022 | 2023 | 2024
The Coteau Properties Company | 13.4 | 11.4 | 11.9
The Falkirk Mining Company | 7.6 | 6.6 | 7.5
Coyote Creek Mining Company | 1.8 | 2.2 | 1.9
Mississippi Lignite Mining Company | 3.2 | 2.7 | 1.9
Totals | 26.0 | 22.9 | 23.2

Table 1.1 Production Summary
2.0 MINING PROPERTIES SUBJECT TO SUBPART 1300 OF REGULATION S-K REPORTING
2.1 Red Hills Mine — Mississippi Lignite Mining Company
MLMC is the owner and operator of the Red Hills Mine. The Red Hills Mine is a lignite surface mine in production. Prior to MLMC, there were no previous mining operations on the Red Hills Mine property.
The MLMC contract is the only operating coal contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our 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.
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A summary of coal production at MLMC for the past three years has been tabulated and is presented on Table 2.1 Production Summary.

| Tons (in millions)
| 2022 | 2023 | 2024
Mississippi Lignite Mining Company | 3.2 | 2.7 | 1.9

Table 2.1 Production Summary
The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started operations in 2000 for plant commissioning, with initial commercial deliveries starting in 2001, and full production and commercial deliveries starting in 2002. All production from the mine is delivered to MLMC's customer's Red Hills Power Plant. During 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations.
The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi (Figure 2.1). 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 8,090 acres of surface interest and 5,150 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,423 acres of coal interests and the right to utilize approximately 4,890 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,683 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.
The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.
The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Reform Water Association. Fuel for equipment is supplied by a local vendor. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations.
Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.
Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.
The Red Hills Mine is in close proximity to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.
In addition to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman, and is accessible by Highway 9 and Highway 15. MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 1, 2032. No mineral processing occurs at the Red Hills Mine.
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The geology encountered at the Red Hills Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Red Hills Mine.
Development of the Red Hills Mine began in 1997, with full commercial deliveries commencing in 2002. The mining operation is comprised of four major equipment fleets. Primary removal of burden is achieved with one 82-cubic yard electric-powered dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.
The mine office facilities and original equipment fleets at the Red Hills Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment 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, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.
The total cost of the property and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2024 is $52.5 million.
The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One notice of violation (NOV) was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. A second NOV was issued in June 2022 for a water sampling violation. Both NOVs were not related to the mining permit. Permitting requirements are discussed in Section 17.0 of the TRS.
Figure 2.1 – Red Hills Mine Location
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Mineral Resources and Reserves have been summarized from the December 31, 2024 TRS for MLMC. The Mineral Resources and Mineral Reserves as of December 31, 2024 are included as Table 2.2 and Table 2.3. Coal qualities are reported on an as-received moisture basis. Based on the December 31, 2024 TRS, prices in Table 2.2 are based on economic cut-off grades of $34.02 per ton at MLMC and prices in Table 2.3 are based on economic cut-off grades of $34.40 per ton at MLMC.
Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed TRS for the MLMC – Red Hills Mine dated December 31, 2024.
Section 11.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Resources. Assumptions include a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $34.02 per ton. A further description of the verified drilling data used to model the lignite deposit for estimation of Mineral Resources is provided in Section 7.2 Drilling Exploration, 8.0 Sample Preparation, Analyses, and Security, and Section 9.0 Data Verification.
Section 12.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Reserves, and include the following:
•Maximum stripping ratio: 14:1;
•Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;
•Mining costs on a unit basis remain relatively consistent with historical performance;
•Minimum minable lignite thickness: 1.0 feet;
•Minimum parting thickness before seams are composited: 6.0 inches;
•Maximum depth of mining: approximately 320 feet;
•Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft³; and
•Recovery rates by seam ranging from 67% to 100%.
Modifying factors including dilution parameters and technical information related to the mining process are described in detail under Section 13.0 Mining Methods. Economic factors to support the Mineral Reserve estimates are described in Section 18.0 Capital and Operating Costs and 19.0 Economic Analyses.
The Mineral Resources as of December 31, 2024 presented in Table 2.2 below have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources reported herein are exclusive of Mineral Reserves.

Lignite Coal | Resource Classification | Tonnage ( Kt) | Grades/Qualities
Calorific Value (Btu/lb) | Moisture (%wt) | Ash (%wt) | Sulfur (%wt)
Mississippi Lignite Mining Company | Measured | 4,400 | 5,200 | 44.6 | 13.0 | 0.6
Mississippi Lignite Mining Company | Indicated | 400 | 5,180 | 44.1 | 13.6 | 0.6
Mississippi Lignite Mining Company | Measured + Indicated | 4,700 | 5,200 | 44.5 | 13.0 | 0.6
Mississippi Lignite Mining Company | Inferred | 100 | 5,200 | 45.5 | 12.0 | 0.5

Note:
–Mineral Resources estimates have been prepared by a qualified person employed by NACCO Natural Resources as of December 31, 2024.
–Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral Resources will be converted into Mineral Reserves.
–Mineral Resources are in-situ and exclusive of 22.9 million tons (Mt) of Mineral Reserves.
–Mineral Resources are reported using an economic cutoff of $34.02 per ton.
–Resources are presented with a minimum 1 foot seam thickness, a maximum as received moisture basis ash content of 30%, and a minimum calorific value of 4000 BTU/lb on an as received moisture basis cutoff.
–Resources are estimated using Vulcan Software.
–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.
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Table 2.2 Mineral Resources Summary as of December 31, 2024
The Mineral Reserves as of December 31, 2024 presented in Table 2.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

Lignite Coal | Reserve Classification | Tonnage (Kt) | Grades/Qualities
Calorific Value (Btu/lb) | Moisture (%wt) | Ash (%wt) | Sulfur (%wt)
Mississippi Lignite Mining Company | Proven | 18,200 | 5,090 | 43.3 | 14.9 | 0.6
Mississippi Lignite Mining Company | Probable | 4,700 | 5,080 | 43.1 | 15.1 | 0.6
Mississippi Lignite Mining Company | Total | 22,900 | 5,090 | 43.3 | 14.9 | 0.6

Note:
–Mineral Reserves Estimates have been prepared by a qualified person employed by MLMC as of December 31, 2024.
–Mineral Reserves have been demonstrated to be economic based on a positive cash flow
–Mineral Reserves are stated on a Run of Mine basis
–An economic cutoff in the Life of Mine plan averaged $34.41 per ton and was used to demonstrate coal reserves
–Recovery varies by coal seam and ranges from 67% to 100%
–Mineral Reserves use an economic cut-off of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.
–Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.
–Mineral Reserves are estimated using Vulcan Software.
–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.
Table 2.3 Mineral Reserves Summary as of December 31, 2024
Table 2.4 describes the difference between the Mineral Reserves and Mineral Resources reported as of December 31, 2023 and December 31, 2024.

Resource Classification | December 31, 2023 Tonnage (Kt) | December 31, 2024 Tonnage (Kt) | Percent Change
Measured | 4,300 | 4,400 | 2%
Indicated | 500 | 400 | (20)%
Measured + Indicated | 4,800 | 4,700 | (2)%
Inferred | 1,600 | 100 | (94)%
Reserve Classification | December 31, 2023 Tonnage (Kt) | December 31, 2024 Tonnage (Kt) | Percent Change
Proven | 15,100 | 18,200 | 21%
Probable | 7,400 | 4,700 | (36)%
Proven + Probable | 22,500 | 22,900 | 2%

Table 2.4. Net difference of reported Mineral Resources and Mineral Reserves from previous reporting period to current reporting period.
The Mineral Resources and Mineral Reserves as of December 31, 2024 reflect modifications from mining extraction of Mineral Reserves, acquisition of additional leased tracts which increased Mineral Reserves and an update to the resource model which allowed conversion of portions of Mineral Resources to Mineral Reserves. The update to the resource model added 31 quality
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core holes and 10 structural drill holes to the resource model. Mining extraction is occurring solely in Mine Area 3. Additionally, MLMC delivered 1.9 million tons during 2024.
2.2 Material Properties with no Mineral Resources or Mineral Reserves
The lignite coal tonnages at Coteau, Falkirk and Coyote Creek have not been classified as measured resources, indicated resources, or inferred resources as defined in Items 1300 through 1305 of Regulation S-K, and as a result, do not have any proven or probable reserves under such definition and are therefore classified as an Exploration Stage Property pursuant to Items 1300 through 1305 of Regulation S-K. Coteau, Falkirk and Coyote Creek will continue to be classified as exploration stage properties until such time as proven or probable mineral reserves have been established in accordance with subpart 1300 of Regulation S-K, even though they continue to deliver lignite to their respective customers.
At Coteau, Coyote Creek and Falkirk, we are 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 our exposure to spot coal market price fluctuations.
Coteau, Coyote Creek and Falkirk each have only one customer for which they extract and deliver coal. These customers operate coal-fired electric generation power plants adjacent to each mine location (and in the case of Coteau, a synthetic natural gas and chemical/fertilizer production facility).
The sales price under the Coteau, Coyote Creek and Falkirk contracts are not market driven. Unlike traditional sales made based on market factors, under the provisions of the long-term mining agreements, the coal sales price at Coteau, Coyote Creek and Falkirk includes (i) all costs incurred to extract, process and deliver coal (i.e. the cost of production) and (ii) the agreed-upon profit per ton of coal or MMBtu unit delivered to the customer. Cost of production includes all the costs actually incurred in the operation of the mine including mining, processing and delivery of coal. Costs included within revenue include all production, transportation and maintenance costs including, without limitation, the following types of costs:
◦Labor, which include wages and all related payroll taxes, benefits and fringes, including welfare plans; group insurance, vacations and other comparable benefits of employees
◦Materials and supplies,
◦Tools,
◦Machinery and equipment not capitalized or leased,
◦Costs of acquiring interests in coal reserves and surface lands,
◦Rental of machinery and equipment,
◦Power costs,
◦Reasonable and necessary services by third parties
◦Insurance including worker’s compensation
◦Certain taxes, and
◦Cost of reclamation
The contractually-determined coal sales price includes reimbursement of all costs incurred and the agreed-upon profit. The agreed-upon profit adjusts based on changes in the level of established indices (e.g., CPI-U and/or PPI indices). The cost-plus nature of the contracts provide assurance that all costs incurred, including contemporaneous and final reclamation, will be reimbursed by the respective customer and negates any risk of loss which allows the mines to remain cash flow positive through the end of the contract terms. The coal sales price as well as profitability at Coteau, Falkirk and Coyote Creek are not subject to any change based on market factors. Profitability at these mines is affected by two factors: demand for coal (because this impacts units of agreed profit that are charged) and changes in the indices that determine coal sales price (because this adjusts the agreed-upon per unit profit). Under any scenario, Coteau, Coyote Creek and Falkirk will be cash flow positive as a result of the terms of the mining agreements.
Extraction of Coteau, Coyote Creek and Falkirk’s lignite tonnages is only economically viable as a result of the long-term mining agreements in place with each mine’s respective customer. The development of the Coteau, Coyote Creek and Falkirk mines was conducted in tandem with the development of the respective mine mouth power plants each serve. The power plants were designed to operate exclusively on the coal provided by the adjacent mines. No other market exists for the lignite at Coteau, Coyote Creek and Falkirk as the cost of transportation makes sales to any entity other than the current mine-mouth operator unprofitable.
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Coteau, Coyote Creek and Falkirk meet the definition of a 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 our 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 our investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets.
Coteau
The Freedom Mine, operated by Coteau, generally produces between 11.5 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. In March 2025, the term of the existing lignite sales agreement was extended until 2032. The term may be extended for an additional five year period, or until 2037, at the option of Coteau.
The Freedom Mine is located approximately 90 miles northwest of Bismarck, North Dakota (Figure 2.2). The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 355 leases granting the right to extract approximately 32,748 acres of coal interests and the right to utilize approximately 22,771 acres of surface interests. In addition, Coteau owns in fee 33,888 acres of surface interests and 4,117 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.
Figure 2.2 – Freedom Mine Location
The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also come from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.
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The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations.
The main entrance to the Freedom Mine is accessed by traveling north of Beulah on Highway 49 for one mile, then north on County Road 21 for two miles, then west on County Road 26 for three miles, and then north on County Road 15 for two miles as shown on Figure 2.2. Location of the Freedom Mine.
Travel to the Freedom Mine by air is possible by means of the Bismarck Municipal Airport, Bismarck, ND, which is approximately 90 miles southeast of the mine. From the airport, the mine is accessed by means of ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 28 miles on ND Highway 49 to Beulah, ND, and so on as explained in the previous paragraph.
Travel to the Freedom Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.
North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.
The coal tonnages are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western 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 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.
Fill-in drilling programs are routinely conducted by Coteau for the purpose of refining guidance related to ongoing operations. It is common practice at the Freedom Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.
Coteau utilizes standard surface mining techniques to extract coal from the proposed permit area. Mining operations will typically occur in a sequence of seven events: suitable plant growth material removal, overburden removal, coal removal, overburden replacement, final grading, suitable plant growth material replacement, and revegetation.
The mine office facilities and original equipment fleets at the Freedom Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment 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, Coteau evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.
The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2024 is $162.2 million.
The Freedom Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Freedom Mine in the past three years. 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.
Falkirk Mine
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. Coal Creek Station was owned by GRE until May 1, 2022 when it was purchased by Rainbow Energy. The initial production period is expected to run through May 1,
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2032, but the coal sales agreement may be extended or terminated early under certain circumstances. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.
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 (Figure 2.3). Falkirk holds 334 leases granting the right to extract approximately 43,015 acres of coal interests and the right to utilize approximately 22,964 acres of surface interests. In addition, Falkirk owns in fee 41,034 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.
The towns of Underwood and Washburn are located within ten miles of the mine, with other small communities also nearby. Numerous employees also reside in Bismarck and Mandan, a distance of about 50 miles.
The Falkirk Mine receives both power and water from Coal Creek Station. However, Falkirk’s East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by multiple local vendors including: Farstad Oil, Missouri Valley Petroleum, and Enerbase Cooperative Resources.
The main entrance to the Falkirk Mine is accessed by traveling north from Bismarck on State Highway 83 for approximately 50 miles, then going west on the access road, 1st Street SW located four miles south of Underwood. The mine office is located two miles to the west.
Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via US Highway 83.
The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.
The coal tonnages 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 coal occurs 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.
Operationally, overburden and interburden removal are accomplished using scrapers, dozers, front end loaders, truck shovel fleets, and draglines. Lignite is mined with front end loaders or hydraulic backhoes, and loaded into haul trucks to transport to the stockpile or directly to the customer via truck dumps and conveyors.
Fill-in drilling programs are routinely conducted by Falkirk for the purpose of refining guidance related to ongoing operations. It is common practice at the Falkirk Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 1320-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.
The mine office facilities and original equipment fleets at the Falkirk Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment 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, Falkirk evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.
The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2024 is $58.7 million.
The Falkirk Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Falkirk Mine in the past three years. There are no outstanding permits related to the 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.
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Figure 2.3 – Falkirk Mine Location
Coyote Creek
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. The term of the existing lignite sales agreement terminates in 2040.
The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota (Figure 2.4). 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.
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Figure 2.4 – Coyote Creek Mine Location
The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply and employment base. A vast supply and employment base also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.
The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and Montana-Dakota Utilities Co., and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations.
The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 1.0 Location of Coyote Creek Mine.
Travel to the Coyote Creek Mine by air is possible using the Bismarck Municipal Airport, Bismarck, ND, approximately 75 miles southeast of the mine. From the airport, the mine is accessed using ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 21 miles on ND Highway 49 to County Road 25, then west for four miles on County Road 25.
Travel to the Coyote Creek Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.
North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.
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The coal tonnages are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western 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 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.
Fill-in drilling programs are routinely conducted by Coyote Creek for the purpose of refining guidance related to ongoing operations. It is common practice at the Coyote Creek Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.
Operationally, overburden removal is accomplished using scrapers, dozers, front end loaders, excavators, truck fleets, and a dragline. Lignite is mined with front end loaders, and loaded into haul trucks to transport to the coal stockpile.
The mine office facilities and original equipment fleets at the Coyote Creek Mine were constructed, acquired, or purchased during the development stage of the mine. The facilities and equipment 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, Coyote Creek evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.
The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2024 is $105.9 million.
The Coyote Creek Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Coyote Creek Mine in the past three years. 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.
3.0 Internal Control Disclosure Over Mineral Resources and Reserves
The modeling and analysis of our resources and reserves has been developed by our mine personnel and reviewed by several levels of internal management, including the QPs. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QPs and Company staff. This section summarizes the internal control considerations for our 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 QPs and our management team 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 QPs.
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 were used to develop these estimations. Review teams were created by utilizing subject matter experts from across all of NACCO to review the cost assumptions and estimations used as the basis of the classification of mineral resources and reserves.
Geological modeling and mine planning efforts serve as a base assumption for resource estimates at MLMC. These outputs have been prepared and reviewed by Company personnel. Mine planning decisions are determined and agreed upon by our 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 our and our customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the deposit. Geologic modeling assumptions are evaluated to historic mining results and are adjusted if necessary to better reflect actual mining results. Ongoing quality validation of production also provides a means to monitor for
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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, changes in QPs, identifying hazards and informing 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.
4.0 Customer-owned Properties
South Hallsville No. 1 Mine — The Sabine Mining Company
The Sabine Mining Company (Sabine) operated the Sabine Mine in Texas. All production from Sabine was delivered to Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries in the first quarter of 2023 and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.
5.0 Facilities and Equipment
The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2024 is set forth in the chart below:

Location |  | Mining Method |  | Total Historical Cost of Mine Property, Plant and Equipment, Net of Applicable Accumulated Amortization, Depreciation and Impairment
Unconsolidated Mining Operations |  |  |  | (in millions)
Freedom Mine — The Coteau Properties Company |  | Dragline operation with 3 draglines |  | $ | 162.2 |
Falkirk Mine — The Falkirk Mining Company |  | Dragline operation with 4 draglines |  | $ | 58.7 |
Coyote Creek Mine — Coyote Creek Mining Company, LLC |  | Dragline operation with 1 dragline |  | $ | 105.9 |
Consolidated Mining Operations |  |  |  |
Red Hills Mine — Mississippi Lignite Mining Company |  | Dragline operation with 1 dragline |  | $ | 52.5 |

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. At December 31, 2024, NAMining operated 31 draglines and other equipment at 23 quarries. Of the 31 draglines, 7 are owned by us and 24 are owned by customers. At December 31, 2024, NAMining had $72.7 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 2024:

Location Name | Aggregate | Location | State | Customer | Year NACCO Started Operations
White Rock — North | Limestone | Miami | FL | WRQ | 1995
Krome | Limestone | Miami | FL | Cemex | 2003
Alico | Limestone | Ft. Myers | FL | Cemex | 2004
FEC | Limestone | Miami | FL | Cemex | 2005
SCL | Limestone | Miami | FL | Cemex | 2006
Central State Aggregates | Limestone | Zephyrhills | FL | McDonald Group | 2016
Mid Coast Aggregates | Limestone | Sumter County | FL | McDonald Group | 2016
West Florida Aggregates | Limestone | Hernando County | FL | McDonald Group | 2016
St. Catherine | Limestone | Sumter County | FL | Cemex | 2016
Center Hill | Limestone | Sumter County | FL | Cemex | 2016
Inglis | Limestone | Crystal River | FL | Cemex | 2016
Titan Corkscrew | Limestone | Ft. Myers | FL | Titan America | 2017
Palm Beach Aggregates | Limestone | Loxahatchee | FL | Palm Beach Aggregates | 2017
Perry | Limestone | Lamont | FL | Martin Marietta | 2018
SDI Aggregates | Limestone | Florida City | FL | Martin Marietta | 2018
Queenfield | Sand and gravel | King William County | VA | Holcim Group | 2018
Newberry | Limestone | Alachua County | FL | Summit Materials/Quikrete | 2019
Seven Diamonds | Limestone | Pasco County | FL | Summit Materials/Quikrete | 2021
Little River | Sand and gravel | Ashdown | AR | Heidelberg Materials | 2021
Rosser | Sand and gravel | Ennis | TX | Heidelberg Materials | 2021
Brooksville Cement Plant | Limestone | Brooksville | FL | Cemex | 2021
Ash Grove | Limestone | Louisville | NE | Ash Grove, A CRH Company | 2022
MDL(a) | Phosphate | Polk County | FL | Mineral Development, LLC | 2024

(a) The MDL quarry was idled during 2024. NAMining mined de minimis amounts at this location during 2024.
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 Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.
Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.
Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.
Access to the St. Catherine mine is by means of a paved road from County Road 673.
Access to the Center Hill mine is by means of a paved road from West Kings Highway.
Access to the Inglis mine is by means of a paved road from Highway 19 South.
Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.
Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.
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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 167 th AVE.
Access to the Queenfield Mine is by means of paved road from Dabney's Mill Road (SR 604).
Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).
Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.
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.
Access to Ash Grove Louisville Quarry is by means of a paved road from HWY 50.
Access to MDL Quarry is by means of Noralyn Mine Road.
Minerals Management - Operations
As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do 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 our mineral interests at a given point in time is not determinable. The following table sets forth our estimate of the number of gross and net productive wells:

| December 31, 2024 |  | December 31, 2023
| Gross |  | Net |  | Gross |  | Net
Oil | 1,295 |  | 4.3 |  | 1,646 |  | 6.6
Natural Gas | 922 |  | 18.5 |  | 246 |  | 13.5
Total | 2,217 |  | 22.8 |  | 1,892 |  | 20.1

Gross wells are the total wells in which an interest is owned.
Net wells are calculated based on our net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.
The majority of our 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 our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royalty interest.
The following table includes our estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs:

| December 31, 2024 |  | December 31, 2023
| Gross Acres |  | Net Royalty Acres |  | Gross Acres |  | Net Royalty Acres
Appalachia | 34,661 |  | 36,199 |  | 34,661 |  | 36,199
Gulf Coast | 27,932 |  | 20,105 |  | 27,932 |  | 20,105
Permian | 121,437 |  | 4,568 |  | 120,636 |  | 4,556
Rockies | 13,233 |  | 659 |  | 326 |  | 72
Williston | 1,194 |  | 2,388 |  | 1,194 |  | 2,388
Total | 198,457 |  | 63,919 |  | 184,749 |  | 63,320

We 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 our ownership and royalty rate, normalized to a standard 1/8 th royalty lease, and assumes a 1/4 th royalty rate for unleased acres.
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The following table includes our estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs:

|  | December 31, 2024 |  | December 31, 2023
|  | Developed Acreage |  | Undeveloped Acreage |  | Gross Acreage |  | Developed Acreage |  | Undeveloped Acreage |  | Gross Acreage
Appalachia |  | 32,156 |  | 2,505 |  | 34,661 |  | 32,156 |  | 2,505 |  | 34,661
Gulf Coast |  | 22,191 |  | 5,741 |  | 27,932 |  | 22,191 |  | 5,741 |  | 27,932
Permian |  | 118,021 |  | 3,416 |  | 121,437 |  | 117,220 |  | 3,416 |  | 120,636
Rockies |  | 7,696 |  | 5,537 |  |  | 13,233 |  | 326 |  | — |  |  | 326
Williston |  | — |  |  | 1,194 |  | 1,194 |  | — |  |  | 1,194 |  | 1,194
Total |  | 180,064 |  |  | 18,393 |  | 198,457 |  | 171,893 |  | 12,856 |  | 184,749

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 our mineral and royalty interests as well as certain price and cost information for the years ended December 31:

|  | 2024 (4) |  | 2023 (4)
Production data: |  |  |  |
Oil (bbl) (1) |  | 149,529 |  |  | 98,553 |
NGL (bbl) (1) |  | 65,053 |  |  | 56,768 |
Residue gas (Mcf) (2) |  | 8,482,414 |  |  | 7,601,521 |
Total BOE (3) |  | 1,628,318 |  |  | 1,422,241 |
Average realized prices: |  |  |  |
Oil (bbl) (1) |  | $ | 78.45 |  |  | $ | 72.19 |
NGL (bbl) (1) |  | $ | 22.94 |  |  | $ | 23.33 |
Residue gas (Mcf) (2) |  | $ | 2.08 |  |  | $ | 2.37 |
Average unit cost |  |  |  |
BOE (3) |  | $ | 2.79 |  |  | $ | 3.32 |

(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.
(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, our access to information concerning activity and operations of our royalty and mineral interests is limited. As a result, we estimated the last two months of 2024 and 2023 production and pricing data using projections based on decline rates of wells and prior expense information.
Evaluation and Review of Reserves
The reserve estimates as of December 31, 2024 were prepared by Haas & Cobb Petroleum Consultants (Haas & Cobb). Haas & Cobb is an independent, third-party, petroleum engineering firm that meets industry-standards for qualifications, independence, objectivity and confidentiality. The primary technical person, Franklin Stagg, responsible for preparing the Reserve Report, Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas & Cobb since 2016 and has over 9 years of industry experience. Haas & Cobb does not own an interest in NACCO or any of our properties, nor is it employed on a contingent basis. A copy of Haas & Cobb's estimated proved reserve report as of December 31, 2024 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.
The properties evaluated for proved reserves are located in Alabama, Louisiana, New Mexico, Ohio, Pennsylvania, Texas, Utah and Wyoming and represent all of our 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
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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 our natural gas and hydrocarbon liquid reserves 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, we employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our 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 our 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.
The following table presents our estimated net proved oil and natural gas reserves based on the reserve report prepared by Haas & Cobb, our independent petroleum engineering firm. All of our reserves are located in the United States.

|  | Net reserves as of December 31, 2024 |  | Net reserves as of December 31, 2023
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2) |  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2)
Proved developed |  | 620,790 |  |  | 443,650 |  |  | 27,491,840 |  |  | 656,370 |  |  | 380,650 |  |  | 23,596,110 |
Proved undeveloped |  | 74,400 |  |  | 30,280 |  |  | 135,830 |  |  | 9,020 |  |  | 3,720 |  |  | 26,420 |
Total |  | 695,190 |  |  | 473,930 |  |  | 27,627,670 |  |  | 665,390 |  |  | 384,370 |  |  | 23,622,530 |

(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.
We do not currently have any material investments under which it would be required to bear the cost of exploration, production or development. We did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.
Internal Control Disclosure
Our internal staff works closely with Haas & Cobb 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.
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The preparation of our proved reserve estimates is 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 our royalty and mineral interests;
•Preparation of reserve estimates by Haas & Cobb under the direct supervision of internal staff; and
•Verification of property ownership by our land department.
The Minerals Management Segment’s Vice President of Engineering and Finance is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas & Cobb in the preparation of the third-party reserve report. The Vice President of Engineering and Finance has over 15 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, our business unit focused on managing and expanding our portfolio of oil and gas mineral and royalty interests.
Estimated Proved Reserves
The following table summarizes changes in proved reserves during the year ended December 31, 2024:

|  | Estimated Proved Reserves
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2) |
December 31, 2023 |  | 665,390 |  |  | 384,370 |  |  | 23,622,530 |  |
Purchases |  | 14,005 |  |  | 1,233 |  |  | 29,268 |  |
Extensions and discoveries |  | 236,491 |  |  | 85,087 |  |  | 7,040,710 |  |
Revisions of previous estimates (3) |  | (105,479) |  |  | 63,441 |  |  | (498,627) |  |
Production |  | (32,077) |  |  | (15,687) |  |  | (1,843,911) |  |
Other |  | (83,140) |  |  | (44,514) |  |  | (722,300) |  |
December 31, 2024 |  | 695,190 |  |  | 473,930 |  |  | 27,627,670 |  |

Estimated Proved Undeveloped Reserves (PUDs)
The following table summarizes changes in PUDs during the year ended December 31, 2024:

|  | Estimated Proved Undeveloped Reserves
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2) |
December 31, 2023 |  | 9,020 |  |  | 3,720 |  |  | 26,420 |  |
Purchases |  | 2,208 |  |  | 38 |  |  | 5,237 |  |
Extensions and discoveries |  | 69,716 |  |  | 27,902 |  |  | 126,724 |  |
Conversions |  | (3,322) |  |  | (1,914) |  |  | (10,017) |  |
Revisions of previous estimates (3) |  | (3,222) |  |  | 534 |  |  | (12,534) |  |
December 31, 2024 |  | 74,400 |  |  | 30,280 |  |  | 135,830 |  |

(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.
(3) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
As an owner of mineral and royalty interests, we generally do not have evidence or approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2024, PUD reserves consists of 89 wells in various stages of drilling or completions. As of December 31, 2024, less than 1% of our total proved reserves were classified as PUDs.
Headquarter locations
NACCO leases office space in Highland Hills, Ohio, a suburb of Cleveland, Ohio, which serves as our corporate headquarters.
Coal Mining and Minerals Management lease corporate headquarters office space in Plano, Texas.
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NAMining leases office and warehouse space in Medley, Florida.
Item 3. LEGAL PROCEEDINGS
We are not a party to any material legal proceeding other than ordinary routine litigation incidental to our 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 Wall Street Reform and Consumer Protection 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 our 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, 2024, there were 648 Class A common stockholders of record and 110 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, 2024 | — |  |  | $ | — |  |  | — |  |  | $ | 8,909,786 |
November 1 to 30, 2024 | — |  |  | $ | — |  |  | — |  |  | $ | 8,909,786 |
December 1 to 31, 2024 | 12,610 |  |  | $ | 29.20 |  |  | 12,610 |  |  | $ | 8,541,574 |
Total | 12,610 |  |  | $ | 29.20 |  |  | 12,610 |  |  | $ | 8,541,574 |

(1) On November 7, 2023, our Board of Directors approved a stock purchase program providing for the purchase of up to $20.0 million of our outstanding Class A common stock through December 31, 2025. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of our stock repurchase programs.
Item 6. [RESERVED]
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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) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources and with NACCO collectively, the Company, we, our or us). NACCO Natural Resources brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate 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. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (Catapult) business, acquires and promotes the development of mineral interests. Mitigation Resources of North America® (Mitigation Resources) provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services. In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.
We have items not directly attributable to a reportable segment that are not included in the reported financial results of the operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, and the financial results of Bellaire Corporation (Bellaire), Mitigation Resources, ReGen Resources and other developing businesses. Bellaire manages our long-term liabilities related to former Eastern U.S. underground mining activities.
All financial statement line items below operating profit (loss) (other income, including interest expense and interest income, the provision (benefit) for income taxes and net income (loss)) 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
Our discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires us 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, we evaluate our 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.
We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the consolidated financial statements.
Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. We account 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 our revenue recognition.
Long-lived assets: We periodically evaluate long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, we evaluate the carrying value of the asset by comparing the estimated future
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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)
undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset or asset group 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.
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 future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. We determined that indicators of impairment existed at MLMC during the fourth quarter of 2023 and, as a result, MLMC's long-lived assets were reviewed for impairment. We assessed the recoverability of the MLMC asset group and determined that the assets were not fully recoverable when compared to the remaining future undiscounted cash flows from these assets. As a result, we estimated the fair value of the asset group which resulted in a non-cash, long-lived asset impairment charge of $65.9 million in 2023.
See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of our impairment analysis.
Income taxes: We file income tax returns in the U.S. federal jurisdiction, and in various state and foreign jurisdictions. 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 the benefit associated with percentage depletion (tax deductions for depletion that may exceed the tax basis in the mineral reserve) and 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.
Our tax assets, liabilities, and tax expense are supported by historical earnings and losses and our best estimates and assumptions of future earnings. We assess whether a valuation allowance should be established against our 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 we use to manage the underlying businesses. When we determine, 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 our financial statements or tax returns, the ultimate resolution of these events could result in adjustments to our financial statements and such adjustments could be material. We believe 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 our results of operations and financial position. Since 2021, we have participated in a voluntary program with the IRS called Compliance Assurance Process (CAP). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return.
See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our 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
Our results of operations were as follows for the years ended December 31:

| 2024 |  | 2023
Revenues: |  |  |
Coal Mining | $ | 68,611 |  |  | $ | 85,415 |
NAMining | 119,600 |  |  | 90,532 |
Minerals Management | 34,579 |  |  | 32,985 |
Unallocated Items | 17,707 |  |  | 8,459 |
Eliminations | (2,789) |  |  | (2,597) |
Total revenue | $ | 237,708 |  |  | $ | 214,794 |
Operating profit (loss): |  |  |
Coal Mining | $ | 24,311 |  |  | $ | (71,342) |
NAMining | 5,772 |  |  | 3,348 |
Minerals Management | 28,927 |  |  | 19,418 |
Unallocated Items | (23,317) |  |  | (21,461) |
Eliminations | 12 |  |  | (100) |
Total operating profit (loss) | $ | 35,705 |  |  | $ | (70,137) |
Interest expense | 5,566 |  |  | 2,460 |
Interest income | (4,428) |  |  | (6,081) |
Closed mine obligations | 2,381 |  |  | 3,585 |
Gain on equity securities | (1,805) |  |  | (1,958) |
Other, net | 345 |  |  | (3,985) |
Other expense (income), net | 2,059 |  |  | (5,979) |
Income (loss) before income tax benefit | 33,646 |  |  | (64,158) |
Income tax benefit | (95) |  |  | (24,571) |
Net income (loss) | $ | 33,741 |  |  | $ | (39,587) |
Effective income tax rate | (0.3) | % |  | 38.3 | %

The components of the change in revenues and operating profit are discussed below in Segment Results.
Other expense (income), net
Interest expense increased in 2024 compared with 2023 due to higher average borrowings as well as an increase in interest rates.
Interest income decreased in 2024 compared with 2023 due to lower earnings on reduced cash balances.
Gain on equity securities represents changes in the market price of invested assets reported at fair value. The change during 2024 compared with 2023 was due to fluctuations in the market prices of the exchange-traded equity securities. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of our invested assets reported at fair value.
During 2023, our Board of Directors approved the termination of the Combined Defined Benefit Plan and participants were offered lump-sum distributions as part of the termination process. As a result of the lump-sum distributions, we recognized a non-cash, pension settlement charge of $1.8 million in 2023 on the line Other, net within the accompanying Consolidated Statements of Operations. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Defined Benefit 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)
On December 1, 2022, we transferred our ownership interest in Midwest AgEnergy Group, LLC (MAG) to HLCP Ethanol Holdco, LLC. We received cash payments totaling $3.6 million during 2023 in connection with MAG and recognized the gain on the line Other, net within the accompanying Consolidated Statements of Operations.
Income Taxes
We recorded an income tax benefit of $0.1 million for the year ended December 31, 2024 on income before income tax of $33.6 million, or 0.3%, compared to an income tax benefit of $24.6 million on loss before income tax of $64.2 million, or 38.3%, for the year ended December 31, 2023. The years ended December 31, 2024 and 2023 both included $4.0 million of discrete tax benefits, primarily from the reversal of uncertain tax provisions. Excluding the $4.0 million of discrete tax benefits in each year, the effective income tax rate in 2024 and 2023 was 11.5% and 32.0%, respectively.
The change in the effective income tax rate for 2024 compared to 2023, excluding the impact of the long-lived asset impairment charge and discrete items, is primarily due to an increase in earnings at entities that do not qualify for percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where income or loss before income tax is relatively small, the proportional effect of the benefit from percentage depletion on the effective tax rate may be significant. When income tax expense is recorded, the benefit from percentage depletion decreases the effective income tax rate, while the effect is to increase the effective income tax rate when a benefit for income taxes is recorded.
See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our 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)
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following tables detail the change in cash flow for the years ended December 31:

| 2024 |  | 2023 |  | Change
Operating activities: |  |  |  |  |
Net income (loss) | $ | 33,741 |  |  | $ | (39,587) |  |  | $ | 73,328 |
Depreciation, depletion and amortization | 24,652 |  |  | 29,387 |  |  | (4,735) |
Deferred income taxes | 1,517 |  |  | (21,114) |  |  | 22,631 |
Stock-based compensation | 5,832 |  |  | 5,157 |  |  | 675 |
(Gain) loss on sale of assets | (5,146) |  |  | 221 |  |  | (5,367) |
Inventory impairment charges | 9,643 |  |  | 7,514 |  |  | 2,129 |
Long-lived asset impairment charge | — |  |  | 65,887 |  |  | (65,887) |
Other | (3,352) |  |  | 1,473 |  |  | (4,825) |
Working capital changes | (44,598) |  |  | 5,552 |  |  | (50,150) |
Net cash provided by operating activities | 22,289 |  |  | 54,490 |  |  | (32,201) |
Investing activities: |  |  |  |  |
Expenditures for property, plant and equipment and acquisition of mineral interests | (55,419) |  |  | (82,122) |  |  | 26,703 |
Proceeds from the sale of assets | 822 |  |  | 561 |  |  | 261 |
Proceeds from the sale of private company equity units | — |  |  | 3,574 |  |  | (3,574) |
Equity method investment | (16,556) |  |  | (3,464) |  |  | (13,092) |
Other | (139) |  |  | (146) |  |  | 7 |
Net cash used for investing activities | (71,292) |  |  | (81,597) |  |  | 10,305 |
Cash flow before financing activities | $ | (49,003) |  |  | $ | (27,107) |  |  | $ | (21,896) |

The $32.2 million unfavorable change in net cash provided by operating activities during 2024 compared with 2023 was primarily due to an unfavorable change in cash provided by working capital, partially offset by an increase in cash provided by net income adjusted for non-cash items. The unfavorable change in working capital was mainly the result of:
•A significant reduction in the Federal income tax receivable during 2023 that did not reoccur in 2024.
•The changes in Inventory during the period as coal inventory increased during 2024 compared with a decrease in 2023. In addition, there was a larger increase in mining supplies inventory during 2024.
•An increase in Trade accounts receivable during 2024 compared with a decrease during 2023, primarily due to changes in the level and timing of collections as well as the payment terms provided to various customers.
Our non-cash items primarily include Long-lived asset impairment charge, Inventory impairment charges, Depreciation, depletion and amortization, Deferred income taxes, Stock-based compensation and (Gain) loss on sale of assets.
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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)

| 2024 |  | 2023 |  | Change
Financing activities: |  |  |  |  |
Net additions to long-term debt and revolving credit agreements | $ | 55,710 |  |  | $ | 11,023 |  |  | $ | 44,687 |
Debt issuance costs | (2,415) |  |  | — |  |  | $ | (2,415) |
Cash dividends paid | (6,624) |  |  | (6,452) |  |  | (172) |
Purchase of treasury shares | (9,944) |  |  | (3,103) |  |  | (6,841) |
Net cash provided by financing activities | $ | 36,727 |  |  | $ | 1,468 |  |  | $ | 35,259 |

The change in net cash provided by financing activities was primarily due to higher additions in debt borrowings during 2024 compared with 2023, partially offset by increased share repurchases and debt issuance costs during 2024. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of our stock repurchase programs.
1031 exchange transactions
During 2024, we had cash proceeds from the sale of assets held by a qualified intermediary to facilitate tax-deferred exchange transactions under Section 1031 of the Internal Revenue Code. In May 2024, we sold land for $7.0 million and recognized a $4.5 million gain in the Minerals Management segment. We structured this transaction in a manner that qualified as a like-kind exchange pursuant to Section 1031 of the Internal Revenue Code and used all of the net proceeds from the sale during the year ended December 31, 2024.
Financing Activities
In September 2024, NACCO Natural Resources amended the secured revolving line of credit (Facility) to increase the revolving credit commitments to $200.0 million and extend the maturity to September 2028. Borrowings outstanding under the Facility were $70.0 million at December 31, 2024. At December 31, 2024, the excess availability under the Facility was $99.1 million, which reflects a reduction for outstanding letters of credit of $30.9 million.
NACCO has not guaranteed any borrowings of NACCO Natural Resources. The Facility allows for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by the Facility) and management fees are the primary sources of cash for NACCO and enable us to pay dividends to stockholders and repurchase shares.
The Facility has performance-based pricing, which sets interest rates based upon NACCO Natural Resources achieving various levels of debt to EBITDA ratios, as defined in the 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, 2024, for base rate and Term Secured Overnight Financing Rate loans were 1.50% and 2.50%, respectively. The Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.40% on the unused commitment at December 31, 2024. During the years ended December 31, 2024 and December 31, 2023, the average borrowing under the Facility was $27.2 million and $6.2 million, respectively, and the weighted-average annual interest rate was 8.83% and 6.06%, respectively.
The Facility contains restrictive covenants, which require, among other things, NACCO Natural Resources 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 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. At December 31, 2024, NACCO Natural Resources was in compliance with all financial covenants in the Facility.
The obligations under the Facility are guaranteed by certain of NACCO Natural Resources' direct and indirect, existing and future domestic subsidiaries, and is secured by certain assets of NACCO Natural Resources and the guarantors, subject to customary exceptions and limitations.
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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)
We believe funds available from cash on hand, the Facility and operating cash flows will provide sufficient liquidity to meet our operating needs and commitments arising during the next twelve months and until the expiration of the Facility in September 2028.
See Note 8 and Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on our other financing arrangements and leases, respectively.
Expenditures for property, plant and equipment and mineral interests
Following is a table which summarizes actual and planned expenditures (in millions):

| Planned |  | Actual |  | Actual
| 2025 |  | 2024 |  | 2023
NACCO | $ | 58.0 |  |  | $ | 55.4 |  |  | $ | 82.1 |

Planned expenditures for 2025 are expected to be approximately $13 million in the Coal Mining segment, $17 million in the NAMining segment, $20 million in the Minerals Management segment and $8 million in growth businesses included in Unallocated Items.
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 |  |
| 2024 |  | 2023 |  | Change
Cash and cash equivalents | $ | 72,833 |  |  | $ | 85,109 |  |  | $ | (12,276) |
Other net tangible assets | 451,962 |  |  | 349,934 |  |  | 102,028 |
Intangible assets, net | 5,475 |  |  | 6,006 |  |  | (531) |
Net assets | 530,270 |  |  | 441,049 |  |  | 89,221 |
Total debt | (99,514) |  |  | (35,956) |  |  | (63,558) |
Closed mine obligations | (25,809) |  |  | (22,753) |  |  | (3,056) |
Total equity | $ | 404,947 |  |  | $ | 382,340 |  |  | $ | 22,607 |
Debt to total capitalization | 20 | % |  | 9 | % |  | 11 | %

The increase in other net tangible assets was mainly the result of increases in Property, plant and equipment, Other non-current assets and Inventory during 2024. The increase in Other non-current asset was primarily due to our investment of $15.7 million in Eiger, which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. The increase in Inventory was mainly due to higher mining supplies and coal inventory.
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 our decisions to contribute above the minimum regulatory funding requirements. We do not expect to contribute to our pension plan in 2025 and any settlements will be paid out of pension plan assets. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds. NACCO also expects to make payments related to our other postretirement plans. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on future benefit payments.
NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of our asset retirement obligations.
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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 unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our income taxes.
We are a party to certain guarantees related to Coyote Creek. We believe that the likelihood of future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of our guarantees.
We utilize letters of credit to support commitments made in the ordinary course of business. As of December 31, 2024 and 2023, outstanding letters of credit totaled $30.9 million and $34.9 million, respectively.
ENVIRONMENTAL MATTERS
We are 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, we closely monitor 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 election of Donald Trump, paired with Republican control of Congress, is likely to have a significant and favorable impact on the regulatory environment, particularly for fossil fuels. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. Our policies stress environmental responsibility and compliance with these regulations. See Item 1 and Item 1A. 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 29 in this Form 10-K for discussion of our mineral resources and mineral reserves.
Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:

| 2024 |  | 2023
Unconsolidated mines | 21,308 |  |  | 20,741 |
Consolidated mines | 1,922 |  |  | 2,931 |
Total tons delivered | 23,230 |  |  | 23,672 |

The results of operations for the Coal Mining segment were as follows for the years ended December 31:

| 2024 |  | 2023
Revenues | $ | 68,611 |  |  | $ | 85,415 |
Cost of sales | 79,375 |  |  | 108,760 |
Gross loss | (10,764) |  |  | (23,345) |
Earnings of unconsolidated operations(a) | 51,821 |  |  | 44,633 |
Business interruption insurance recoveries | 13,612 |  |  | — |
Selling, general and administrative expenses and long-lived asset impairment charge | 30,112 |  |  | 89,971 |
Amortization of intangible assets | 531 |  |  | 2,998 |
Gain on sale of assets | (285) |  |  | (339) |
Operating profit (loss) | $ | 24,311 |  |  | $ | (71,342) |

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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) See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of our unconsolidated subsidiaries, including summarized financial information.
2024 Compared with 2023
Revenues decreased 19.7% in 2024 compared with 2023 due to a reduction in customer requirements at MLMC as a result of a boiler issue at the customer's Red Hills Power Plant.
The following table identifies the components of change in Operating profit (loss) for 2024 compared with 2023:

| Operating Profit (Loss)
2023 | $ | (71,342) |
Increase (decrease) from: |
Long-lived asset impairment charge in 2023 | 60,832 |
Business interruption insurance recoveries | 13,612 |
Gross loss, excluding inventory impairment charges | 14,710 |
Earnings of unconsolidated operations | 7,188 |
Amortization of intangibles | 2,467 |
Inventory impairment charges | (2,129) |
Selling, general and administrative expenses | (973) |
Net change on sale of assets | (54) |
2024 | $ | 24,311 |

Operating profit (loss) changed favorably by $95.7 million in 2024 compared with 2023. The change in Operating profit (loss) was primarily due to:
•The absence of a long-lived asset impairment charge;
•Business interruption insurance recoveries for the boiler issue at the Red Hills Power Plant;
•A decrease in gross loss, excluding inventory impairment charges;
•An increase in the earnings of unconsolidated operations; and
•A decrease in the amortization of intangibles.
During 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed for impairment and recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023. The $65.9 million relates exclusively to MLMC; however, $60.8 million and $5.1 million were recorded on the Coal Mining segment and the Minerals Management segment, respectively, as certain MLMC land assets were recorded within the Minerals Management segment. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the 2023 impairment. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.
The reduction in revenues at MLMC was offset by lower cost of goods sold, resulting in a decrease in the gross loss during 2024 compared with 2023. The reduction in cost of goods sold was primarily attributable to changes in the level of coal inventory and costs capitalized into inventory as the decrease in demand resulted in an increase in the coal stockpile during 2024. In addition, the gross loss in 2024 and 2023 included $9.6 million and $7.5 million of inventory impairment charges, respectively, to write down MLMC's coal inventory to its net realizable value.
The increase in earnings of unconsolidated operations was primarily due to improved results at Falkirk, primarily due to a higher per ton management fee beginning in June 2024 when temporary price concessions ended and an increase in customer demand. Improved results at Coteau also contributed to the increase in earnings of unconsolidated operations.
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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)
NORTH AMERICAN MINING (NAMining) SEGMENT
FINANCIAL REVIEW
Aggregate tons delivered by the NAMining segment were as follows for the years ended December 31:

| 2024 |  | 2023
Total tons delivered | 54,963 |  |  | 56,655 |

The results of operations for the NAMining segment were as follows for the years ended December 31:

| 2024 |  | 2023
Total revenues | $ | 119,600 |  |  | $ | 90,532 |
Reimbursable costs | 74,636 |  |  | 56,611 |
Revenues excluding reimbursable costs | $ | 44,964 |  |  | $ | 33,921 |
Revenues | $ | 119,600 |  |  | $ | 90,532 |
Cost of sales | 110,821 |  |  | 83,719 |
Gross profit | 8,779 |  |  | 6,813 |
Earnings of unconsolidated operations(a) | 5,010 |  |  | 5,361 |
Selling, general and administrative expenses | 8,365 |  |  | 8,308 |
(Gain) loss on sale of assets | (348) |  |  | 518 |
Operating profit | $ | 5,772 |  |  | $ | 3,348 |

(a) See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of our unconsolidated subsidiaries, including summarized financial information.
2024 Compared with 2023
Revenues excluding reimbursable costs increased 32.6% in 2024 compared with 2023, mainly due to favorable pricing and delivery mix at the consolidated limestone quarries and an increase in the scope of work at Sawtooth. Reimbursable costs, which have an offsetting amount in cost of sales and have no impact on gross profit, also increased during 2024.
The following table identifies the components of change in Operating profit for 2024 compared with 2023.

| Operating Profit
2023 | $ | 3,348 |
Increase (decrease) from: |
Gross profit | 1,966 |
Net change on sale of assets | 866 |
Earnings of unconsolidated operations | (351) |
Selling, general and administrative expenses | (57) |
2024 | $ | 5,772 |

Operating profit increased $2.4 million in 2024 compared with 2023 primarily due to an increase in gross profit and a favorable change on the sale of assets. The improvement in gross profit was mainly the result of favorable pricing and improved margins at the consolidated limestone quarries and an increase in the scope of work at Sawtooth.
Selling, general and administrative expenses include a $0.9 million charge to establish an allowance against a receivable from one of NAMining's customers during 2024, which was offset by a reduction in outside services.
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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)
MINERALS MANAGEMENT SEGMENT
FINANCIAL REVIEW
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below shows the average price as reported by the United States Energy Information Administration for the twelve months ended December 31:

|  | 2024 |  | 2023
West Texas Intermediate Average Crude Oil Price |  | $ | 76.55 |  |  | $ | 77.64 |
Henry Hub Average Natural Gas Price |  | $ | 2.19 |  |  | $ | 2.54 |

These indicated prices do not necessarily reflect the contract terms for our sales. As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests.
The results of operations for the Minerals Management segment were as follows for the years ended December 31:

| 2024 |  | 2023
Oil and natural gas revenues | $ | 27,157 |  |  | $ | 22,922 |
Other revenues | 7,422 |  |  | 10,063 |
Total Revenues | $ | 34,579 |  |  | $ | 32,985 |
Total Revenues | $ | 34,579 |  |  | $ | 32,985 |
Cost of sales | 5,234 |  |  | 3,969 |
Gross profit | 29,345 |  |  | 29,016 |
Earnings of unconsolidated operations | 647 |  |  | — |
Selling, general and administrative expenses and asset impairment charge | 5,577 |  |  | 9,556 |
(Gain) loss on sale of assets | (4,512) |  |  | 42 |
Operating profit | $ | 28,927 |  |  | $ | 19,418 |

Revenues increased in 2024 compared with 2023 primarily due to an increase in oil and natural gas revenues as a result of increased oil production volumes related to an acquisition that closed during the fourth quarter of 2023. These improvements were partially offset by a reduction in other revenues, primarily coal royalty income. In addition, revenues during 2023 included $1.4 million of settlement income.
Operating profit increased $9.5 million in 2024 compared with 2023, primarily due to the absence of a $5.1 million long-lived asset impairment charge recognized during 2023 and a $4.5 million gain on the sale of land related to legacy operations recognized during 2024. The increase in revenue was offset by an increase in cost of sales, primarily related to higher depletion expense due to increased production volumes. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the 2023 impairment.
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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:

| 2024 |  | 2023
Operating loss | $ | (23,305) |  |  | $ | (21,561) |

2024 Compared with 2023
The operating loss increased during 2024 compared with 2023 primarily due to higher employee-related costs, partially offset by lower expenses for growth initiatives as certain costs expensed in 2023 were capitalized in 2024.
NACCO Industries, Inc. Outlook
NACCO's businesses provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and chemicals. Increasing demand for electricity, on-shoring and current federal policies are creating favorable macroeconomic trends within these industries. We are confident in our trajectory and business prospects as we enter 2025 and prepare for longer-term growth opportunities. Specifically in 2025, we expect to generate a modest year-over-year increase in consolidated operating profit.
In 2025, the Coal Mining segment anticipates solid customer demand, with deliveries expected to increase modestly from 2024. We anticipate that evolving policy frameworks may create a more favorable regulatory environment for the fossil fuel industry moving forward. These developments are expected to further support coal as an essential part of the energy mix in the United States for the foreseeable future.
The Coal Mining segment expects to benefit from the expiration of temporary price concessions at Falkirk. In addition, MLMC continues to recover from inefficiencies experienced while its customer's Red Hills Power Plant operated on one of two generation units for more than half of 2024. With the power plant now anticipated to operate at a level consistent with historical averages, coal deliveries are expected to return to more normal levels, resulting in moderate cost efficiencies. However, an anticipated reduction in the 2025 contractually determined per ton sales price compared with 2024 is expected to offset these improvements, resulting in lower results at MLMC. An expected increase in operating expenses will contribute to an overall anticipated modest year-over-year decrease in Coal Mining segment operating profit.
NAMining is expected to generate increasing levels of operating profit over time as the benefits of new and extended contracts add to the profitability of existing contracts. During 2024, NAMining executed three new or amended existing contracts, which are expected to deliver net present value after-tax cash flows of approximately $20 million over contract terms that range from 6 to 20 years. NAMining is expected to deliver further improved results in 2025, predominantly in the second half of the year based on expectations for comparable year-over-year customer demand. NAMining is continuously seeking to enter into new or amended contracts to solidify its position as the foundation for NACCO's mining-related growth initiatives.
NAMining's subsidiary, Sawtooth, is the exclusive provider of comprehensive mining services at Thacker Pass, which is owned by Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Sawtooth will supply all of the lithium-bearing ore requirements for Thacker Pass, which is currently under construction. We expect to continue to recognize moderate income at Sawtooth while it assists with certain construction services. Once the mine is operating, Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee. In addition to providing comprehensive mining services, Sawtooth will receive a fee to transport clay tailings once lithium production commences. Phase 1 lithium production is estimated to begin in late 2027.
The Minerals Management segment, through its Catapult business, has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests in the United States. In the fourth quarter of 2024, Minerals Management invested $15.7 million in a company that holds non-operated working interests in oil and natural gas assets in the Kansas and Oklahoma portions of the Hugoton basin. While this investment, accounted for under the equity method, is expected to be accretive to earnings, 2025 operating profit is expected to be comparable to 2024. Lower first-half earnings are expected to be offset by an
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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)
improvement in the second half given expected trends in oil and natural gas prices and projected volumes.
Minerals Management continues to build its portfolio with a mix of producing wells, near-term development opportunities and undeveloped acreage. We believe our data-driven approach to acquisitions and our long-term perspective provides a competitive advantage as undeveloped assets provide additional upside potential over the life of the reserve. While we continue to budget up to $20 million annually to expand our portfolio and provide long-term stable cash flow generation, our business model allows flexibility regarding the cadence and type of investment based on available opportunities that we believe will create long-term value and generate increasing profitability.
Mitigation Resources provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services. This business is an avenue for growth and diversification in an area where NACCO has built a strong reputation based on its substantial knowledge and expertise. Mitigation Resources continued to expand during 2024, and now has 11 mitigation banks and other mitigation projects located in Alabama, Florida, Georgia, Mississippi, Pennsylvania, Tennessee and Texas.
Mitigation Resources also provides ecological restoration services for abandoned surface mines and plans to pursue other environmental restoration projects. It was named a designated provider of abandoned mine land restoration by the State of Texas, and in January 2025 secured a restoration project in Kentucky that is expected to be accretive to earnings beginning in 2026.
Mitigation Resources is expected to achieve full-year profitability beginning in 2025 based on current expectations for the timing of permit approvals and mitigation credit releases, as well as income generated from service-related projects. Mitigation Resources is expected to increase profitability over time, and provide a return on capital employed in the mid-teens as the business matures.
We established ReGen Resources in 2023 to address the rapidly increasing demand for additional power generation sources in the United States through development of energy and energy-related projects that utilize multiple-generation technologies, such as solar combined with gas-fired generation, primarily on reclaimed mining properties. These projects could be developed by ReGen Resources directly or through joint ventures that include partners with expertise in energy development projects. Current projects include solar arrays, solar-gas hybrid projects and carbon capture projects on reclaimed mine land in Mississippi and Texas. Additional projects in other states are in early-stage review.
We are taking actions to terminate our defined benefit pension plan in 2025, which will eliminate future volatility from changes in the pension obligation. Once complete, obligations under the terminated plan will be transferred to a third-party insurance provider. Surplus assets are expected to be utilized to fund a qualified replacement plan, reducing future cash funding requirements. Although the plan is currently over funded, a significant non-cash settlement charge is anticipated upon termination, which is expected to lead to a substantial year-over-year decrease in net income and EBITDA compared with 2024.
Consolidated capital expenditures are expected to total approximately $58 million in 2025, which includes approximately $13 million for Coal Mining, $17 million for NAMining, $20 million for Minerals Management and $8 million predominantly for ReGen Resources and other growth businesses. We expect significant annual cash flow generation beginning in 2025, based on the current business plan.
We believe that each of our businesses have competitive advantages that provide value to customers and create long-term value for stockholders. We are pursuing growth and diversification by strategically leveraging our core natural resources management skills to build a robust portfolio of affiliated businesses. Opportunities for growth remain strong and are increasing amid recent successes and a significant positive change in the regulatory environment, particularly for fossil fuels. Acquisitions of additional mineral interests and improvements in the outlook for Coal Mining segment customers, as well as new contracts at Mitigation Resources and NAMining should be accretive to the longer-term outlook.
We are committed to maintaining a conservative capital structure as we continue to grow and diversify, while avoiding unnecessary risk. We believe strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses or distributed to investors in the form of share repurchases or dividends. We continue to maintain the highest levels
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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 customer service and operational excellence with an unwavering focus on safety and environmental stewardship.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Note 2 to the Consolidated Financial Statements in this Form 10-K for a description of recently issued accounting standards including actual and expected dates of adoption and effects to our Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
The statements contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere throughout this Annual Report on Form 10-K that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of customer or other third-party contracts, or a customer or other third party default under a contract, (2) any customer's premature facility closure or extended project development delay, (3) regulatory actions, including the United States EPA's rules finalized in 2024 relating to mercury and greenhouse gas emissions for coal-fired power plants, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (4) a significant reduction in purchases by the Company's customers, including as a result of changes in coal consumption patterns of U.S. electric power generators, or changes in the power industry that would affect demand for the Company's coal and other mineral reserves, (5) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas, natural gas liquids and oil as a result of factors such as OPEC and/or government actions, geopolitical developments, economic conditions and regulatory changes, as well as supply and demand dynamics, (6) changes in development plans by third-party lessees of the Company's mineral interests, (7) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing and U.S. export of natural gas; and the ability of lessees to obtain capital or financing needed for well-development operations and leasing and development of oil and gas reserves on federal lands, (8) failure to obtain adequate insurance coverages at reasonable rates, (9) supply chain disruptions, including price increases and shortages of parts and materials, (10) changes in tax laws or regulatory requirements, including the elimination of, or reduction in, the percentage depletion tax deduction, changes in mining or power plant emission regulations and health, safety or environmental legislation, (11) impairment charges, (12) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (13) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (14) weather or equipment problems that could affect deliveries to customers, (15) changes in the costs to reclaim mining areas, (16) costs to pursue and develop new mining, mitigation, oil and gas and solar development opportunities and other value-added service opportunities, (17) delays or reductions in coal or aggregates deliveries, (18) the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (19) disruptions from natural or human causes, including severe weather, accidents, fires, earthquakes and terrorist acts, any of which could result in suspension of operations or harm to people or the environment, and (20) the ability to attract, retain, and replace workforce and administrative employees.
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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934, we are not required to provide this information.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item 8 is set forth in the Financial Statements and Supplementary Data contained in Part IV of this Form 10-K and is hereby incorporated herein by reference to such information.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, 2024 that require disclosure pursuant to this Item 9.
Item 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures: An evaluation was carried out under the supervision and with the participation of our management, including the principal executive officer and the principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that our disclosure controls and procedures are effective.
Management's report on internal control over financial reporting: Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that our internal control over financial reporting was effective as of December 31, 2024. Our effectiveness of internal control over financial reporting as of December 31, 2024 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.
Changes in internal control: There have been no changes in our internal control over financial reporting, that occurred during the fourth quarter of 2024, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. OTHER INFORMATION
During the fourth quarter of 2024, none of our directors or executive officers adopted or terminated a Rule 10b5-1 Trading Plan, or a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
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PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information with respect to our Directors will be set forth in the 2025 Proxy Statement under the subheadings Part III — Proposals To Be Voted On At The 2025 Annual Meeting — Proposal 1 — Election of Directors which information is incorporated herein by reference.
Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the 2025 Proxy Statement under the subheading Part I — Corporate Governance Information — Directors' Meetings and Committees, which information is incorporated herein by reference.
Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by our Directors, executive officers and holders of more than ten percent of our equity securities will be set forth in the 2025 Proxy Statement under the subheading Part IV — Other Important Information, which information is incorporated herein by reference.
We have adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the Code of Corporate Conduct, is posted on our website at www.nacco.com under Corporate Governance. If we make any amendments to or grant any waivers from the code of business conduct and ethics which are required to be disclosed pursuant to the Securities and Exchange Act of 1934, we will make such disclosure on the NACCO website.
We have adopted an insider trading policy that governs the purchase, sale and other disposition of our securities by our directors, officers and employees that is designated to promote compliance with insider trading laws, rules, regulations and applicable listing standards. A copy of our insider trading policy is filed as Exhibit 19 to this Annual Report on Form 10-K for the year ended December 31, 2024.
Item 11. EXECUTIVE COMPENSATION
Information with respect to executive compensation will be set forth in the 2025 Proxy Statement under the headings Part II — Executive Compensation Information and Part III — Proposals To Be Voted On At The 2025 Annual Meeting — Proposal 1 — Election of Directors, which information is incorporated herein by reference.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information with respect to security ownership of certain beneficial owners and management will be set forth in the 2025 Proxy Statement under the subheading Part IV — Other Important Information — Beneficial Ownership of Class A Common and Class B Common, which information is incorporated herein by reference.
Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the 2025 Proxy Statement under the subheading Part IV — Other Important Information — Equity Compensation Plan Information, which information is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information with respect to certain relationships and related transactions will be set forth in the 2025 Proxy Statement under the subheadings Part I — Corporate Governance Information — Review and Approval of Related-Person Transactions, which information is incorporated herein by reference.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information with respect to principal accountant fees and services will be set forth in the 2025 Proxy Statement under the heading Part III — Proposals To Be Voted On At The 2025 Annual Meeting — Proposal 4 — Ratification of the Appointment of Company's Independent Registered Public Accounting Firm, which information is incorporated herein by reference.
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PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page F-1 of this Form 10-K.
(b) Financial Statement Schedules — The response to Item 15(c) is set forth beginning at page F-42 of this Form 10-K.
(c) Exhibits required by Item 601 of Regulation S-K

Exhibit Number |  | Exhibit Description
(3) Articles of Incorporation and By-laws.
3.1(i) |  | Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
3.1(ii) |  | Certificate of Ame ndment of the Restated Certificate of Incorporation of the Comp any, dated July 23, 2024, is incorporated herein by referen ce to Exhibit 3(ii) to the Company's Quarterly Report on Form 10-Q, filed by the Company on July 31, 2024, Commis s ion File Number 1-9172.
3.1(iii) |  | Amended and Restated By-laws of the Company are incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed by the Company on December 18, 2014, Commission File Number 1-9172.

(4) Instruments defining the rights of security holders, including indentures.
4.1 |  | The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
4.2 |  | Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed by the Company on October 5, 2017, Commission File Number 1-9172.
4.3 |  | Amendment to Amended and Restated Stockholders' Agreement, dated as of February 14, 2019, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
4.4 |  | Second Amendment to Amended and Restated Stockholders' Agreement, dated as of February 12, 2021, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.60 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2021, Commission File Number 1-9172.
4.5 |  | Third Amendment to Amended and Restated Stockholders' Agreement, dated as of February 11, 2022, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.62 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 11, 2022, Commission File Number 1-9172.
4.6 |  | Fourth Amendment to Amended and Restated Stockholders' Agreement, dated as of February 10, 2023, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.67 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 10, 2023, Commission File Number 1-9172.
4.7 |  | Fifth Amendment to Amended and Restated Stockholders' Agreement, dated as of February 9, 2024, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.69 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2024, Commission File Number 1-9172.

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Exhibit Number |  | Exhibit Description
4.8 |  | Sixth Amendment to Amended and Restated Stockholders’ Agreement, dated as of December 16, 2024, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.71 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on December 17, 2024, Commission File Number 1-9172.
4.9 |  | Description of Securities is incorporated herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
(10) Material contracts
10.1* |  | NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan (Amended and Restated March 1, 2012) is incorporated herein by reference to Appendix B to NACCO's Definitive Proxy Statement, filed by NACCO on March 16, 2012, Commission File Number 1-9172.
10.2* |  | NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2023) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 16, 2023, Commission File Number 1-9172.
10.3* |  | Amendment No. 1 to NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2023), dated as of February 20, 2024, is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on February 22, 2024, Commission File Number 1-9172.
10.4* |  | NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19, 2021) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 19, 2021, Commission File Number 1-9172.
10.5* |  | Amendment No. 1 to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19, 2021), dated as of February 20, 2024, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 22, 2024, Commission File Number 1-9172.
10.6* |  | Form of Award Agreement for the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan is incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed by the Company on September 17, 2012, Commission File Number 1-9172.
10.7* |  | Form of Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 1, 2024, Commission File Number 1-9172.
10.8* |  | Form of Non-Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.9 |  | Consulting Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.5 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on October 5, 2017, Commission File Number 1-9172.
10.10 |  | Amendment to Consulting Agreement, dated as of December 15, 2020, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 15, 2020, Commission File Number 1-9172.
10.11 |  | Amendment to Consulting Agreement, dated as of December 21, 2021, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 22, 2021, Commission File Number 1-9172.
10.12 |  | Amendment to Consulting Agreement, dated as of December 19, 2023, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 19, 2023, Commission File Number 1-9172.
10.13 |  | Amendment to Consulting Agreement, dated as of December 19, 202 4, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 23, 202 4, Commission File Number 1-9172.
10.14* |  | NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.
10.15* |  | The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.

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Exhibit Number |  | Exhibit Description
10.16* |  | Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.
10.17* |  | The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.
10.18* |  | Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.
10.19 |  | Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.20 |  | First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.21 |  | Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.22 |  | Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.23 |  | First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.24 |  | Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.25 |  | First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.
10.26 |  | Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.27 |  | Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.28 |  | Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.29 |  | Amendment No. 2 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 24, 2021, is incorporated herein by reference to Exhibit 10.29 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.
10.30 |  | Termination Agreement and Release, by and among The Falkirk Mining Company, Great River Energy and NoDak Energy Investments Corporation, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.31 |  | Amendment No. 1 to Termination Agreement and Release, by and between The Falkirk Mining Company, NoDak Energy Investments Corporation and Great River Energy, dated as of December 28, 2021, is incorporated herein by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.

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Exhibit Number |  | Exhibit Description
10.32*** |  | Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.33 |  | First Amendment to Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated March 8, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 4, 2022, Commission File Number 1-9172.
10.34 |  | Second Amendment to Coal Sales Agreement, by and between the Falkirk Mining Company and Rainbow Energy Center, LLC, dated August 5, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on November 2, 2022, Commission File Number 1-9172.
10.35*** |  | Guaranty by REMC Assets, LP, dated June 17, 2021, is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.36*** |  | Mortgage, Assignment of Leases, Rents and As-Extracted Collateral, Security Agreement, Financing Statement and Fixture Filing, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.37 |  | Security Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.38 |  | Option Agreement, by and between The Falkirk Mining Company, Rainbow Energy Center, LLC and the State of North Dakota, Doing Business as The Bank of North Dakota, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.39 |  | Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++
10.40 |  | First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.
10.41 |  | Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.42* |  | Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.
10.43* |  | Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.44* |  | Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.
10.45* |  | Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.
10.46 |  | Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.47* |  | The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.

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Exhibit Number |  | Exhibit Description
10.48* |  | The NACCO Natural Resources Excess Retirement Plan (Effective January 1, 2025) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 17, 2024, Commission File Number 1-9172.
10.49 |  | Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Guarantors party thereto and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of November 12, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on November 15, 2021, Commission File Number 1-9172.
10.50 |  | Revolving Credit Commitment Increase Agreement, dated as of December 10, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 13, 2021. Commission File Number 1-9172.
10.51 |  | ESG Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on July 7, 2022. Commission File Number 1-9172.
10.52 |  | First Amendment to Amended and Restated Credit Agreement, dated as of September 17, 2024, among NACCO Natural Resources Corporation, the guarantors party thereto, the lenders party thereto and PNC Bank, National Association, as administrative agent, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on September 19, 2024, Commission File Number 1-9172.
(19**) |  | NACCO Industries, Inc. Insider Trading Policy
(21**) |  | Subsidiaries. A list of the subsidiaries of the Company is attached hereto as Exhibit 21.

(23) Consents of experts and counsel.

23.1** |  | Consents of experts and counsel.
23.2** |  | Consent of Qualified Person.
23.3** |  | Consent of Qualified Person.
23.4** |  | Consent of experts and counsel.

(24) Powers of Attorney.

24.1** |  | A copy of a power of attorney for John S. Dalrymple is attached hereto as Exhibit 24.1.
24.2** |  | A copy of a power of attorney for John P. Jumper is attached hereto as Exhibit 24.2.
24.3** |  | A copy of a power of attorney for Dennis W. LaBarre is attached hereto as Exhibit 24.3.
24.4** |  | A copy of a power of attorney for W. Paul McDonald is attached hereto as Exhibit 24.4.
24.5** |  | A copy of a power of attorney for Michael S. Miller is attached hereto as Exhibit 24.5.
24.6** |  | A copy of a power of attorney for Alfred M. Rankin, Jr. is attached hereto as Exhibit 24.6.
24.7** |  | A copy of a power of attorney for Matthew M. Rankin is attached hereto as Exhibit 24.7.
24.8** |  | A copy of a power of attorney for Roger F. Rankin is attached hereto as Exhibit 24.8.
24.9** |  | A copy of a power of attorney for Lori J. Robinson is attached hereto as Exhibit 24.9.
24.10** |  | A copy of a power of attorney for Valerie Gentile Sachs is attached hereto as Exhibit 24.10.
24.11** |  | A copy of a power of attorney for Robert S. Shapard is attached hereto as Exhibit 24.11.
24.12** |  | A copy of a power of attorney for Britton T. Taplin is attached hereto as Exhibit 24.12.

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Exhibit Number |  | Exhibit Description
(31) Rule 13a-14(a)/15d-14(a) Certifications.
31(i)(1) ** |  | Certification of J.C. Butler, Jr. pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(1).
31(i)(2) ** |  | Certification of Elizabeth I. Loveman pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(2).
(32)**** |  | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed and dated by J.C. Butler, Jr. and Elizabeth I. Loveman.
(95)** |  | Mine Safety Disclosure Exhibit.
96.1** |  | Technical Report Summary relating to the Mississippi Lignite Mining Company, effective date as of December 31, 2024.
(97.1)** |  | NACCO Industries, Inc. Dodd-Frank Clawback Policy
(99.1**) |  | Reserve Report of Catapult Mineral Partners.
101.INS |  | Inline XBRL Instance Document
101.SCH |  | Inline XBRL Taxonomy Extension Schema Document
101.CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB |  | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 |  | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* |  | Management contract or compensation plan or arrangement required to be filed as an exhibit pursuant to Item15(b) of this Annual Report on Form 10-K.
** |  | Filed herewith.
*** |  | Certain confidential information contained in this agreement has been omitted because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.
**** |  | Furnished herewith.
+ |  | Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated March 27, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating Confidential treatment requested.
++ |  | Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated April 2, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating Confidential treatment requested.

Item 16. Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

| NACCO Industries, Inc. |
| By: | /s/ Elizabeth I. Loveman |
|  | Elizabeth I. Loveman |
|  | Senior Vice President and Controller (principal financial and accounting officer) |

March 5, 2025
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ J.C. Butler, Jr. |  | President and Chief Executive Officer (principal executive officer) | March 5, 2025
J.C. Butler, Jr. |  |  |
/s/ Elizabeth I. Loveman |  | Senior Vice President and Controller (principal financial and accounting officer) | March 5, 2025
Elizabeth I. Loveman |  |
*John S. Dalrymple |  | Director | March 5, 2025
John S. Dalrymple |  |  |
* John P. Jumper |  | Director | March 5, 2025
John P. Jumper |  |  |
* Dennis W. LaBarre |  | Director | March 5, 2025
Dennis W. LaBarre |  |  |
* W. Paul McDonald |  | Director | March 5, 2025
W. Paul McDonald |  |  |
* Michael S. Miller |  | Director | March 5, 2025
Michael S. Miller |  |  |
* Alfred M. Rankin, Jr. |  | Director | March 5, 2025
Alfred M. Rankin, Jr. |  |  |
* Matthew M. Rankin |  | Director | March 5, 2025
Matthew M. Rankin |  |  |
* Roger F. Rankin |  | Director | March 5, 2025
Roger F. Rankin |  |  |
*Lori J. Robinson |  | Director | March 5, 2025
Lori J. Robinson |  |  |
* Valerie Gentile Sachs |  | Director | March 5, 2025
Valerie Gentile Sachs |  |  |
*Robert S. Shapard |  | Director | March 5, 2025
Robert S. Shapard |  |  |
* Britton T. Taplin |  | Director | March 5, 2025
Britton T. Taplin |  |  |

* Elizabeth I. Loveman, by signing her name hereto, does hereby sign this Form 10-K on behalf of each of the above named and designated directors pursuant to a Power of Attorney executed by such persons and filed with the Securities and Exchange Commission.

/s/ Elizabeth I. Loveman |  | March 5, 2025
Elizabeth I. Loveman, Attorney-in-Fact |  |

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ANNUAL REPORT ON FORM 10-K
ITEM 8, ITEM 15(a)(1) AND (2), AND ITEM 15(c)
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENTS
FINANCIAL STATEMENT SCHEDULES
YEAR ENDED DECEMBER 31, 2024
NACCO INDUSTRIES, INC.
CLEVELAND, OHIO
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FORM 10-K
ITEM 15(a)(1) AND (2)
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following consolidated financial statements of NACCO Industries, Inc. and Subsidiaries and the reports of our independent registered public accounting firm (PCAOB ID:42) are incorporated by reference in Item 8:

Report of Ernst & Young LLP, Independent Registered Public Accounting Firm — For each of the two years in the period ended December 31, 202 4. | F-3
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — As of December 31, 202 4. | F-5
Consolidated Statements of Operations | F-6
Consolidated Statements of Comprehensive (Loss) Income | F-7
Consolidated Balance Sheets | F-8
Consolidated Statements of Cash Flows | F-9
Consolidated Statements of Equity | F-10
Notes to Consolidated Financial Statements | F-11

The following consolidated financial statement schedules of NACCO Industries, Inc. and Subsidiaries are included in Item 15(c):

Schedule II — Valuation and Qualifying Accounts |

All other schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.
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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of NACCO Industries, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of NACCO Industries, Inc. and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive (loss) income, equity and cash flows for each of the two years in the period ended December 31, 2024, and the related notes and financial statement schedule listed in the Index at Item 15(b) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 5, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit review committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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Unconsolidated subsidiaries – accounting for variable interest entities

Description of the Matter | As discussed in Note 1 and 16 to the consolidated financial statements, certain of the operating coal mines and entities within the NAMining segment, collectively referred to as the “Unconsolidated Subsidiaries,” are variable interest entities (VIEs) and are accounted for under the equity method. In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control. Although NACCO owns 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, the Company has determined that the equity capital provided by NACCO is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct activities that most significantly affect the economic performance of the entities. As a result, the Company is not the primary beneficiary and therefore does not consolidate these entities’ financial position or results of operations. The Company regularly evaluates if there are reconsideration events which could change the Company's conclusion as to whether these entities meet the definition of a VIE and the determination of the primary beneficiary. 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. Evaluating the Company’s judgments in determining whether an entity is a VIE and the primary beneficiary of the VIE at formation and reconsideration events requires a high degree of complex auditor judgment. The Company also monitors for reconsideration events relating to the Unconsolidated Subsidiaries, which necessitates on-going critical judgments over whether any such events have arisen that require a re-evaluation of prior accounting judgments.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated and tested the design and operating effectiveness of the controls surrounding the Company’s application of the variable interest model and the processes to continually assess the implications of significant transactions and events that could trigger a VIE reconsideration event. For those entities where the Company has determined it is not the primary beneficiary, we evaluated the Company’s accounting for and disclosure of the Unconsolidated Subsidiaries under the equity method in accordance with the generally accepted accounting principles. To test the identification of reconsideration events, we obtained and inspected amendments to the agreements with customers, if any, and evaluated evidence from other parts of the audit to determine if a reconsideration event arose that necessitated a re-evaluation of previous accounting judgments. These procedures included, among others, reading board minutes, inquiring of management about transactions or events that could require a reconsideration of previous consolidation conclusions and obtaining direct confirmation of the total annual support provided in accordance with the contractual arrangements from the customers.

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2002.
Cleveland, Ohio
March 5, 2025
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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of NACCO Industries, Inc.
Opinion on Internal Control Over Financial Reporting
We have audited NACCO Industries, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NACCO Industries, Inc. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2024 consolidated financial statements of the Company and our report dated March 5, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Cleveland, Ohio
March 5, 2025
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NACCO INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

| Year Ended December 31
| 2024 |  | 2023
| (In thousands, except per share data)
Revenues | $ | 237,708 |  |  | $ | 214,794 |
Cost of sales | 207,952 |  |  | 200,203 |
Gross profit | 29,756 |  |  | 14,591 |
Earnings of unconsolidated operations | 57,476 |  |  | 49,994 |
Business interruption insurance recoveries | 13,612 |  |  | — |
Operating expenses |  |  |
Selling, general and administrative expenses | 69,754 |  |  | 65,616 |
Amortization of intangible assets | 531 |  |  | 2,998 |
(Gain) loss on sale of assets | (5,146) |  |  | 221 |
Long-lived asset impairment charge | — |  |  | 65,887 |
| 65,139 |  |  | 134,722 |
Operating profit (loss) | 35,705 |  |  | (70,137) |
Other expense (income) |  |  |
Interest expense | 5,566 |  |  | 2,460 |
Interest income | (4,428) |  |  | (6,081) |
Closed mine obligations | 2,381 |  |  | 3,585 |
Gain on equity securities | (1,805) |  |  | (1,958) |
Other, net | 345 |  |  | (3,985) |
| 2,059 |  |  | (5,979) |
Income (loss) before income tax benefit | 33,646 |  |  | (64,158) |
Income tax benefit | (95) |  |  | (24,571) |
Net income (loss) | $ | 33,741 |  |  | $ | (39,587) |
Earnings (loss) per share: |  |  |
Basic earnings (loss) per share | $ | 4.58 |  |  | $ | (5.29) |
Diluted earnings (loss) per share | $ | 4.55 |  |  | $ | (5.29) |
Basic weighted average shares outstanding | 7,363 |  |  | 7,478 |
Diluted weighted average shares outstanding | 7,411 |  |  | 7,478 |

See notes to the Consolidated Financial Statements.
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NACCO INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

| Year Ended December 31
| 2024 |  | 2023
| (In thousands)
Net income (loss) | $ | 33,741 |  |  | $ | (39,587) |
Other comprehensive (loss) income |  |  |
Current period pension and postretirement plan adjustment, net of $205 and $615 tax benefit in 2024 and 2023, respectively | (706) |  |  | (2,118) |
Pension settlement, net of $417 tax benefit in 2023 | — |  |  | 1,398 |
Reclassification of pension and postretirement adjustments into earnings, net of $89 and $24 tax benefit in 2024 and 2023, respectively | 308 |  |  | 79 |
Total other comprehensive loss | (398) |  |  | (641) |
Comprehensive income (loss) | $ | 33,343 |  |  | $ | (40,228) |

See notes to the Consolidated Financial Statements.
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NACCO INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| December 31
| 2024 |  | 2023
| (In thousands, except share data)
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 72,833 |  |  | $ | 85,109 |
Trade accounts receivable | 49,706 |  |  | 37,429 |
Accounts receivable from affiliates | 5,793 |  |  | 7,860 |
Inventories | 94,608 |  |  | 77,000 |
Assets held for sale | 14,159 |  |  | 6,466 |
Other current assets | 27,639 |  |  | 18,134 |
Total current assets | 264,738 |  |  | 231,998 |
Property, plant and equipment, net | 259,457 |  |  | 223,902 |
Intangibles, net | 5,475 |  |  | 6,006 |
Deferred income taxes | 14,641 |  |  | 15,081 |
Investments in unconsolidated subsidiaries | 14,137 |  |  | 12,371 |
Operating lease right-of-use assets | 9,661 |  |  | 8,667 |
Equity securities | 18,663 |  |  | 17,208 |
Equity method investment in Eiger, LLC | 19,147 |  |  | 2,800 |
Other non-current assets | 25,768 |  |  | 21,675 |
Total assets | $ | 631,687 |  |  | $ | 539,708 |
LIABILITIES AND EQUITY |  |  |
Current liabilities |  |  |
Accounts payable | $ | 17,721 |  |  | $ | 16,702 |
Accounts payable to affiliates | 1,826 |  |  | 904 |
Revolving credit agreements | — |  |  | 10,000 |
Current maturities of long-term debt | 4,179 |  |  | 3,953 |
Asset retirement obligations | 9,747 |  |  | 13,114 |
Accrued payroll | 22,663 |  |  | 17,317 |
Other current liabilities | 8,752 |  |  | 7,996 |
Total current liabilities | 64,888 |  |  | 69,986 |
Long-term debt | 25,335 |  |  | 22,003 |
Long-term revolving credit agreement | 70,000 |  |  | — |
Operating lease liabilities | 9,042 |  |  | 8,782 |
Asset retirement obligations | 39,780 |  |  | 39,499 |
Pension and other postretirement obligations | 4,787 |  |  | 5,183 |
Liability for uncertain tax positions | 794 |  |  | 5,795 |
Other long-term liabilities | 12,114 |  |  | 6,120 |
Total liabilities | 226,740 |  |  | 157,368 |
Stockholders’ equity |  |  |
Common stock: |  |  |
Class A, par value $1 per share, 5,730,470 shares outstanding (2023 - 5,882,845 shares outstanding) | 5,730 |  |  | 5,883 |
Class B, par value $1 per share, convertible into Class A on a one-for-one basis, 1,565,359 shares outstanding (2023 - 1,565,819 shares outstanding) | 1,566 |  |  | 1,566 |
Capital in excess of par value | 34,340 |  |  | 28,672 |
Retained earnings | 373,363 |  |  | 355,873 |
Accumulated other comprehensive loss | (10,052) |  |  | (9,654) |
Total stockholders’ equity | 404,947 |  |  | 382,340 |
Total liabilities and equity | $ | 631,687 |  |  | $ | 539,708 |

See notes to the Consolidated Financial Statements.
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NACCO INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

| Year Ended December 31
| 2024 |  | 2023
| (In thousands)
Operating Activities |  |  |
Net income (loss) | $ | 33,741 |  |  | $ | (39,587) |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation, depletion and amortization | 24,652 |  |  | 29,387 |
Amortization of deferred financing fees | 619 |  |  | 505 |
Deferred income taxes | 1,517 |  |  | (21,114) |
Stock-based compensation | 5,832 |  |  | 5,157 |
(Gain) loss on sale of assets | (5,146) |  |  | 221 |
Inventory impairment charges | 9,643 |  |  | 7,514 |
Long-lived asset impairment charge | — |  |  | 65,887 |
Other | (3,971) |  |  | 968 |
Working capital changes: |  |  |
Accounts receivable | (11,725) |  |  | 2,519 |
Inventories | (27,250) |  |  | (12,971) |
Other current assets | (8,677) |  |  | (1,904) |
Accounts payable | 1,955 |  |  | 3,148 |
Income taxes receivable/payable | (148) |  |  | 14,996 |
Other current liabilities | 1,247 |  |  | (236) |
Net cash provided by operating activities | 22,289 |  |  | 54,490 |
Investing Activities |  |  |
Expenditures for property, plant and equipment | (54,706) |  |  | (45,408) |
Acquisition of mineral interests | (713) |  |  | (36,714) |
Proceeds from the sale of assets | 822 |  |  | 561 |
Equity method investment | (16,556) |  |  | (3,464) |
Proceeds from the sale of private company equity units | — |  |  | 3,574 |
Other | (139) |  |  | (146) |
Net cash used for investing activities | (71,292) |  |  | (81,597) |
Financing Activities |  |  |
Net additions to revolving credit agreement | 60,000 |  |  | 10,000 |
Additions to long-term debt | 624 |  |  | 5,232 |
Reductions to long-term debt | (4,914) |  |  | (4,209) |
Debt issuance costs | (2,415) |  |  | — |
Cash dividends paid | (6,624) |  |  | (6,452) |
Purchase of treasury shares | (9,944) |  |  | (3,103) |
Net cash provided by financing activities | 36,727 |  |  | 1,468 |
Cash and Cash Equivalents |  |  |
Total decrease for the year | (12,276) |  |  | (25,639) |
Balance at the beginning of the year | 85,109 |  |  | 110,748 |
Balance at the end of the year | $ | 72,833 |  |  | $ | 85,109 |

See notes to the Consolidated Financial Statements.
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NACCO INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY

| Class A Common Stock | Class B Common Stock | Capital in Excess of Par Value | Retained Earnings | Accumulated Other Comprehensive (Loss) Income | Total Stockholders' Equity
| (In thousands, except per share data)
Balance, January 1, 2023 | $ | 5,783 |  | $ | 1,566 |  | $ | 23,706 |  | $ | 404,924 |  | $ | (9,013) |  | $ | 426,966 |
Stock-based compensation | 191 |  | — |  | 4,966 |  | — |  | — |  | 5,157 |
Purchase of treasury shares | (91) |  | — |  | — |  | (3,012) |  | — |  | (3,103) |
Net loss | — |  | — |  | — |  | (39,587) |  | — |  | (39,587) |
Cash dividends on Class A and Class B common stock: $0.8600 per share | — |  | — |  | — |  | (6,452) |  | — |  | (6,452) |
Current period other comprehensive income, net of tax | — |  | — |  | — |  | — |  | (2,118) |  | (2,118) |
Pension settlement, net of tax | — |  | — |  | — |  | — |  | 1,398 |  | 1,398 |
Reclassification adjustment to net income, net of tax | — |  | — |  | — |  | — |  | 79 |  | 79 |
Balance, December 31, 2023 | $ | 5,883 |  | $ | 1,566 |  | $ | 28,672 |  | $ | 355,873 |  | $ | (9,654) |  | $ | 382,340 |
Stock-based compensation | 164 |  | — |  | 5,668 |  | — |  | — |  | 5,832 |
Purchase of treasury shares | (317) |  | — |  | — |  | (9,627) |  | — |  | (9,944) |
Net income | — |  | — |  | — |  | 33,741 |  | — |  | 33,741 |
Cash dividends on Class A and Class B common stock: $0.9000 per share | — |  | — |  | — |  | (6,624) |  | — |  | (6,624) |
Current period other comprehensive income, net of tax | — |  | — |  | — |  | — |  | (706) |  | (706) |
Reclassification adjustment to net income, net of tax | — |  | — |  | — |  | — |  | 308 |  | 308 |
Balance, December 31, 2024 | $ | 5,730 |  | $ | 1,566 |  | $ | 34,340 |  | $ | 373,363 |  | $ | (10,052) |  | $ | 404,947 |

See notes to the Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 1—Principles of Consolidation and Nature of Operations
The accompanying Consolidated Financial Statements include the accounts of NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources and with NACCO collectively, the Company, we, our or us). NACCO Natural Resources brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate 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. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (Catapult) business, acquires and promotes the development of mineral interests. Mitigation Resources of North America® (Mitigation Resources) provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services. In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.
We have items not directly attributable to a reportable segment that are not included in the reported financial results of the operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, and the financial results of Bellaire Corporation (Bellaire), Mitigation Resources, ReGen Resources and other developing businesses. Bellaire manages our long-term liabilities related to former Eastern U.S. underground mining activities. Intercompany accounts and transactions are eliminated in consolidation. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.
Our operating segments are further described below:
Coal Mining Segment
The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with our customer's operations.
As of December 31, 2024, the Coal Mining segment's operating coal mines were: The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and Mississippi Lignite Mining Company (MLMC). Each of these mines supply lignite coal for power generation and delivers our coal production to an adjacent power plant or synfuels plant under a long-term supply contract. While MLMC’s coal supply contract contains a take or pay provision, the contract contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party; all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.
The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our 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's customer operates the Red Hills Power Plant, which supplies electricity to the Tennessee Valley Authority (TVA) under a long-term power purchase agreement. MLMC’s contract with its customer runs through April 1, 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC.
During 2023, MLMC received notice from our customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed MLMC's long-lived assets for impairment and recorded a $65.9 million impairment charge in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our results of operations during 2024. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries to partially offset losses related to the boiler outage.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas. All production from Sabine was delivered to
Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American
Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.
At Coteau, Coyote Creek and Falkirk, we are 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. Our customers are responsible for funding all mine operating costs, including final mine
reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing 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 us. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.
Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity (VIE). In each case, NACCO
is not the primary beneficiary of the VIE as we do not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, these contracts are accounted for as equity method investments. We regularly evaluate if there are reconsideration events which could change our conclusion as to whether these entities meet the definition of a VIE and the determination of the primary beneficiary. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations and our 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 our consolidated U.S. tax return; therefore, the Income tax benefit line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.
We perform contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.
NAMining Segment
The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for our growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for our customers by performing the mining aspects of our customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of December 31, 2024, NAMining operates in Florida, Texas, Arkansas, Virginia and Nebraska.
In addition, Sawtooth Mining, LLC (Sawtooth) will be the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada. Thacker Pass is owned by a joint venture between Lithium Americas Corp. (TSX:LAC) (NYSE: LAC) and General Motors Holdings LLC. Thacker Pass commenced construction in 2023 and is targeting initial production in 2027. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services, Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences
During 2024 and 2023, NAMining amended and extended existing limestone contracts with two customers and expanded the scope of work with several other customers. New contracts signed in 2024 are expected to be accretive to earnings starting in 2026.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Minerals Management Segment
The Minerals Management segment derives income primarily by leasing our 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 Minerals Management segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests (collectively mineral and 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 royalty interests may be calculated net of post-production expenses, and typically have no environmental liability. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.
•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. The NPRI owner does; however, typically receive royalty payments.
•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.
We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own 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 does not currently have any material investments under which we would be required to bear the cost of exploration, production or development. The Minerals Management segment will benefit from the continued
development of our mineral properties without the need for investment of additional capital once mineral and royalty interests
have been acquired as the capital costs or lease operating expenses are born entirely by the operators or working interest
owners.
During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of
2024, in Eiger, LLC (Eiger), which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. This entity meets the definition of a VIE. NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, this contract is accounted for as an equity method investment. During 2024, we recorded $0.6 million, which represented our share of earnings, as Earnings of unconsolidated operations on the Consolidated Statements of Operations. Our investment is reported on the line Equity method investment in Eiger, LLC in the Consolidated Balance Sheets. Due to a lag in Eiger's financial reporting, earnings or losses from this investment will be recorded on a one quarter lag.
Excluding the Eiger investment described above, total consideration for acquisitions of mineral and royalty interests was $0.7 million and $36.7 million, in 2024 and 2023, respectively. The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres. The 2023 acquisitions included 43.4 thousand gross acres and 2.5 thousand net royalty acres.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
We also manage legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of our legacy reserves were acquired as part of our historical coal mining operations.
Total oil and gas mineral and royalty interests include approximately 198.4 thousand gross acres and 63.9 thousand net royalty acres at December 31, 2024. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8 th royalty lease, and assumes a 1/4 th royalty rate for unleased acres. See Note 17 for further discussion of Minerals Management.
Other items: At December 31, 2024 and 2023, we had $14.2 million and $6.5 million classified as Assets held for sale, primarily for draglines at NAMining and a building, respectively.
During 2024, we had cash proceeds from the sale of assets held by a qualified intermediary to facilitate tax-deferred exchange transactions under Section 1031 of the Internal Revenue Code. In May 2024, we sold land for $7.0 million and recognized a $4.5 million gain in the Minerals Management segment, which is included on the line (Gain) loss on sale of assets within the accompanying Consolidated Statements of Operations. We structured this transaction in a manner that qualified as a like-kind exchange pursuant to Section 1031 of the Internal Revenue Code and used all of the net proceeds from the sale during the year ended December 31, 2024.
During 2023, our Board of Directors approved the termination of the Combined Defined Benefit Plan (Combined Plan) and participants were offered lump-sum distributions as part of the termination process. As a result of the lump-sum distributions, we recognized a non-cash, pension settlement charge of $1.8 million in 2023 on the line Other, net within the accompanying Consolidated Statements of Operations. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.
On December 1, 2022, we transferred our ownership interest in Midwest AgEnergy Group, LLC (MAG) to HLCP Ethanol Holdco, LLC. We received cash payments totaling $3.6 million during 2023 in connection with MAG and recognized the gain on the line Other, net within the accompanying Consolidated Statements of Operations.
NOTE 2—Significant Accounting Policies
Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and judgments. These estimates and judgments affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents: Cash and cash equivalents include cash in banks and highly liquid investments with original maturities of three months or less.
Property, Plant and Equipment, Net: Property, plant and equipment are initially recorded at cost. Depreciation, depletion and amortization are provided in amounts sufficient to amortize the cost of the assets, including assets recorded under finance leases, over their estimated useful lives using the straight-line method or the units-of-production method. Buildings and building improvements are depreciated over the life of the asset, which is generally 30 years. Estimated lives for machinery and equipment generally range from three to 15 years. The units-of-production method is used to amortize certain assets based on estimated recoverable tonnages. Repairs and maintenance costs are expensed when incurred, unless such costs extend the estimated useful life of the asset, in which case such costs are capitalized and depreciated. Asset retirement costs associated with asset retirement obligations are capitalized with the carrying amount of the related long-lived asset and depreciated over the asset's estimated useful life.
Royalty Interests in Oil and Natural Gas Properties: We follow the successful efforts method of accounting for royalty and mineral interests. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of royalty interests of oil and natural gas properties are considered asset acquisitions and are recorded at cost. As an owner of mineral and royalty interests and not working interests, we are not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Acquisition costs of proved royalty and mineral interests are amortized using the units of production method over the life of the property, which is estimated using proved reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.
We review and evaluate our royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. When such events or changes in circumstances occur, we estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties.
See Note 17 for further discussion of our royalty and mineral interests.
Long-Lived Assets: We periodically evaluate long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, we evaluate the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset or asset group 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.
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 future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. We determined that indicators of impairment existed at MLMC during the fourth quarter of 2023 and, as a result, MLMC's long-lived assets were reviewed for impairment. We assessed the recoverability of the MLMC asset group and determined that the assets were not fully recoverable when compared to the remaining future undiscounted cash flows from these assets. As a result, we estimated the fair value of the asset group which resulted in a non-cash, long-lived asset impairment charge of $65.9 million in 2023.
See Note 9 for further discussion of our impairment analysis.
Self-insurance Liabilities: We are generally self-insured for medical claims, certain workers’ compensation claims and certain closed mine liabilities. An estimated provision for claims reported and for claims incurred but not yet reported under the self-insurance programs is recorded and revised periodically based on industry trends, historical experience and management judgment. In addition, industry trends are considered within management's judgment for valuing claims. Changes in assumptions for such matters as legal judgments and settlements, inflation rates, medical costs and actual experience could cause estimates to change in the near term.
Revenue Recognition: See Note 3 to the Consolidated Financial Statements for discussion of our revenue recognition.
Stock Compensation: We maintain a long-term incentive program that allow for the grant of shares of Class A common stock, subject to restrictions, as a means of retaining and rewarding selected employees for long-term performance and to increase their ownership in NACCO. Shares awarded under the plans are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged or otherwise transferred during the restriction period. In general, for shares awarded for years ended December 31, 2024 and December 31, 2023, the restriction period ends at the earliest of (i) three years after the participant's retirement date, (ii) three, five or ten years from the award date, or (iii) the participant's death or permanent disability. Pursuant to the plans, we issued 162,670 and 120,649 shares related to the years ended December 31, 2024 and 2023, respectively. After the issuance of these shares, there were 616,681 shares of Class A common stock available for issuance under these plans. Compensation expense related to these share awards was $5.2 million ($4.1 million net of tax) and $4.1 million ($3.3 million net of tax) for the years ended December 31, 2024 and 2023, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.
We also have a stock compensation plan for non-employee directors under which a portion of the annual retainer for each non-employee director is paid in restricted shares of Class A common stock. For the year ended December 31, 2024 and 2023, $110,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $175,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. Shares awarded under the plan are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged, hypothecated or
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
otherwise transferred during the restriction period. In general, the restriction period ends at the earliest of (i) ten years from the award date, (ii) the date of the director's death or permanent disability, (iii) five years (or earlier with the approval of the Board of Directors) after the director's date of retirement from the Board of Directors, (iv) the date the director has both retired from the Board of Directors and has reached age 70, or (v) at such other time as determined by the Board of Directors in their sole and absolute discretion. Pursuant to this plan, we issued 44,731 and 35,965 shares related to the years ended December 31, 2024 and 2023, respectively. In addition to the mandatory retainer fee received in restricted stock, directors may elect to receive shares of Class A common stock in lieu of cash for up to 100% of the balance of their annual retainer, committee retainer and any committee chairman's fees. These voluntary shares are not subject to any restrictions. There were no shares issued under voluntary elections in 2024. Total shares issued under voluntary elections were 1,603 in 2023. After the issuance of these shares, there were 53,748 shares of Class A common stock available for issuance under this plan. Compensation expense related to these awards was $1.3 million ($1.0 million net of tax) and $1.3 million ($1.1 million net of tax) for the years ended December 31, 2024 and 2023, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.
Financial Instruments: Financial instruments held by us include cash and cash equivalents, accounts receivable, equity securities, accounts payable, revolving credit agreements and long-term debt.
Fair Value Measurements: We account for the fair value measurement of our financial assets and liabilities in accordance with U.S. generally accepted accounting principles, which defines fair value 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.
A fair value hierarchy requires an entity to maximize the use of observable inputs, where available, and minimize the use of unobservable inputs when measuring fair value.
Described below are the three levels of inputs that may be used to measure fair value:
Level 1 - Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.
Level 2 - Observable prices that are based on inputs not quoted on active markets, but corroborated by market data.
Level 3 - Unobservable inputs are used when little or no market data is available.
The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. See Note 9 for further discussion of fair value measurements.
Recently Issued Accounting Standards
Accounting Standards Adopted in 2024: Effective for the year ended December 31, 2024, we adopted ASU No. 2023-07, Segment Reporting (Topic 280), (ASU 2023-07), which enhances reportable segment disclosure requirements in part by requiring entities to disclose significant expenses related to their reportable segments. ASU 2023-07 also requires disclosure of the title and position of the company’s Chief Operating Decision Maker (CODM) and how the CODM uses financial reporting to assess segment performance and allocate resources. The adoption of this standard only impacts disclosures and did not have a material impact on our Financial Statements.
Accounting Standards Not Yet Adopted: In December 2023, the Financial Accounting Standards Board (FASB) issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (ASU 2023-09), which requires entities to disclose more detailed information about their effective tax rate reconciliation as well as information on income taxes paid. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024. The adoption of this standard only impacts disclosures and is not expected to have a material impact on our Financial Statements.
In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40) (ASU 2024-03), which requires entities to disclose disaggregated information about certain income statement expense line items in the notes to their financial statements on an annual and interim basis. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. We are currently in the process of evaluating the impact of this ASU on our Financial Statements and related disclosures.
Reclassification: Certain reclassifications have been made to the prior periods’ Consolidated Financial Statements to conform to the current period's presentation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 3—Revenue Recognition
Nature of Performance Obligations
At contract inception, we assess the goods and services promised in our contracts with customers and identifies a performance obligation for each promised good or service that is distinct. To identify the performance obligations, we consider all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.
Each mine or mine area has a contract with our respective customer that represents a contract under ASC 606. For our consolidated entities, our performance obligations vary by contract and consist of the following:
At MLMC, each MMBtu delivered during the production period is considered a separate performance obligation. Revenue is recognized at the point in time that control of each MMBtu of lignite transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand.
At NAMining, the management service to oversee the operation of the equipment and delivery of aggregates or other minerals is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee and the general and administrative fee (as applicable). Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels on individual contracts and variances in reimbursable costs. Revenue from part sales is recognized upon transfer of control of the parts to the customer.
The Minerals Management segment enters into contracts which grant the right to explore, develop, produce and sell minerals controlled by us. These arrangements result in the transfer of mineral rights for a period of time; however, no rights to the actual land are granted other than access for purposes of exploration, development, production and sales. The mineral rights revert back to us at the expiration of the contract.
Under these contracts, granting exclusive right, title, and interest in and to minerals, if any, is the performance obligation. The performance obligation under these contracts represents a series of distinct goods or services whereby each day of access that is provided is distinct. The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of an up-front lease bonus payment. As the amount of consideration we will ultimately be entitled to is entirely susceptible to factors outside of our control, the entire amount of variable consideration is constrained at contract inception. We believe that the pricing provisions of royalty contracts are customary in the industry. Up-front lease bonus payments represent the fixed portion of the transaction price and are recognized over the primary term of the contract, which is generally three to five years.
Mitigation Resources generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Each mitigation credit sale is considered a separate performance obligation. Revenue is recognized at the point in time that control of each mitigation credit transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand. Under the permittee-responsible stream and wetland mitigation model, the contracts are generally structured as a management fee agreement under which Mitigation Resources is reimbursed for all costs incurred in performing the required mitigation plus an agreed profit percentage or a fixed fee. The mitigation services provided is the performance obligation and is accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer as work is completed. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee. Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels of individual contracts and variances in reimbursable costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Significant Judgments
Our contracts with our customers in the Coal Mining and NAMining segments contain different types of variable consideration including, but not limited to, management fees that adjust based on volumes or MMBtu delivered. However, the terms of these variable payments relate specifically to our efforts to satisfy one or more, but not all, of the performance obligations (or to a specific outcome from satisfying the performance obligations) in the contract. Therefore, we allocate each variable payment (and subsequent changes to that payment) entirely to the specific performance obligation to which it relates. Management fees, as well as general and administrative fees, are also adjusted based on changes in specified indices (e.g., CPI) to compensate for general inflation changes. Index adjustments, if applicable, are effective prospectively.
In the Minerals Management segment, we have the right to receive revenues from the sale of oil and natural gas through sales of the third-party lessees in which we own a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred from the operator to the purchaser. Those purchasers remit payment to the operator and the operator, in turn, remits payment to us. Receivables from third-party lessees for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated using expected sales volumes and estimated prices. The difference between our estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. We typically receive payment for oil and natural gas sales within 90 days of the month of delivery. For the years ended December 31, 2024 and 2023, differences between our estimates and the actual amounts received from operators were immaterial. For the years ended December 31, 2024 and 2023, any changes in estimates were immaterial.
Cost Reimbursement
Certain contracts include reimbursement from customers of actual costs incurred for the purchase of supplies, equipment and services in accordance with contractual terms. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our control. Accordingly, reimbursable revenue is fully constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are considered a principal in such transactions and records the associated revenue at the gross amount billed to the customer with the related costs recorded as an expense within cost of sales.
At the Thacker Pass lithium project, in addition to management fee income, the customer will reimburse Sawtooth for certain capital expenditures. Sawtooth will recognize revenue over the estimated useful life of the asset on a straight-line basis as the performance obligation is satisfied over time. In prior years, the customer received a $3.5 million advance from Sawtooth, which is included in the long-term contract asset. The customer will either pay a $4.7 million success fee to Sawtooth upon achieving commercial mining milestones or repay the $3.5 million advance if such commercial mining milestones are not met.
Prior Period Performance Obligations
As discussed above, we record royalty income in the month production is delivered to the purchaser. The expected sales volumes and prices for these properties are estimated and recorded in Trade accounts receivable in the accompanying Consolidated Balance Sheets. The difference between our estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. During the years ended December 31, 2024 and 2023, royalty income recognized in the reporting period related to production satisfied in prior reporting periods was immaterial and $1.4 million, respectively.
Disaggregation of Revenue
In accordance with ASC 606-10-50, we disaggregate revenue from contracts with customers into major goods and service lines and timing of transfer of goods and services. We determined that disaggregating revenue into these categories achieves the disclosure objective of depicting how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Our business consists of the Coal Mining, NAMining and Minerals Management segments as well as Unallocated Items. Revenue included in Unallocated Items is primarily related to Mitigation Resources. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The following table disaggregates revenue by major sources for the years ended December 31:

Major Goods/Service Lines | 2024 |  | 2023
Coal Mining | $ | 68,611 |  |  | $ | 85,415 |
NAMining | 119,600 |  |  | 90,532 |
Minerals Management | 34,579 |  |  | 32,985 |
Unallocated Items | 17,707 |  |  | 8,459 |
Eliminations | (2,789) |  |  | (2,597) |
Total revenues | $ | 237,708 |  |  | $ | 214,794 |
Timing of Revenue Recognition |  |  |
Goods transferred at a point in time | $ | 66,506 |  |  | $ | 83,273 |
Services transferred over time | 171,202 |  |  | 131,521 |
Total revenues | $ | 237,708 |  |  | $ | 214,794 |

Contract Balances
The opening and closing balances of our current and long-term contract assets and liabilities and receivables are as follows:

| Contract balances
| Trade accounts receivable |  | Contract asset (current) |  | Contract asset (long-term) |  | Contract liability (current) |  | Contract liability (long-term)
Balance at January 1, 2024 | $ | 37,429 |  |  | $ | — |  |  | $ | 3,712 |  |  | $ | 878 |  |  | $ | 1,470 |
Balance at December 31, 2024 | 49,706 |  |  | 313 |  |  | 3,500 |  |  | 484 |  |  | 5,119 |
Increase (decrease) | $ | 12,277 |  |  | $ | 313 |  |  | $ | (212) |  |  | $ | (394) |  |  | $ | 3,649 |

As described above, we enter into royalty contracts that grant exclusive right, title, and interest in and to minerals.
The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of
an up-front lease bonus payment. The timing of the payment of the fixed portion of the transaction price is upfront, however,
the performance obligation is satisfied over the primary term of the contract, which is generally three to five years. Therefore, at the time any such up-front payment is received, a contract liability is recorded which represents deferred revenue. The amount of royalty revenue recognized in the years ended December 31, 2024 and December 31, 2023 that was included in the opening contract liability was $0.7 million and $0.8 million, respectively. This revenue consists of up-front lease bonus payments received under royalty contracts that are recognized over the primary term of the royalty contracts, which are generally three to five years.
We expect to recognize $0.5 million in 2025, $0.1 million in 2026 and 2027, $1.0 million in 2028, $2.4 million in 2029 and $1.5 million thereafter related to the contract liability remaining at December 31, 2024. The difference between the opening and closing balances of our contract balances results from the timing difference between our performance and the customer’s payment.
We have no contract assets recognized from the costs to obtain or fulfill a contract with a customer.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 4—Inventories
Inventories are summarized as follows:

| December 31
| 2024 |  | 2023
Coal | $ | 27,076 |  |  | $ | 23,784 |
Mining supplies | 67,532 |  |  | 53,216 |
Total inventories | $ | 94,608 |  |  | $ | 77,000 |

The weighted average method is used for inventory valuation. During the year ended December 31, 2024 and 2023, we recorded $9.6 million and $7.5 million of inventory impairment charges, respectively, in the line Cost of sales in the accompanying Consolidated Statements of Operations as mining costs exceeded net realizable value of coal inventory at MLMC.
NOTE 5—Property, Plant and Equipment, Net
Property, plant and equipment, net includes the following:

| December 31
| 2024 |  | 2023
Coal lands and real estate | $ | 70,766 |  |  | $ | 58,353 |
Mineral interests | 69,148 |  |  | 68,150 |
Plant and equipment | 317,933 |  |  | 325,655 |
Property, plant and equipment, at cost | 457,847 |  |  | 452,158 |
Less allowances for depreciation, depletion, amortization and impairment | 198,390 |  |  | 228,256 |
| $ | 259,457 |  |  | $ | 223,902 |

Total depreciation, depletion and amortization expense on property, plant and equipment was $24.1 million and $26.4 million during 2024 and 2023, respectively.
During 2023, we recorded a non-cash, long-lived asset impairment charge of $65.9 million. See Note 9 for further discussion of the impairment charge.
NOTE 6—Intangible Assets
We have a coal supply agreement intangible asset which is subject to amortization based on units of production over the term of the lignite sales agreement which expires in 2032. The gross and net balances are set forth in the following table:

| Gross Carrying Amount |  | Accumulated Amortization and Impairment |  | Net Balance
Balance at December 31, 2024 |  |  |  |  |
Coal supply agreement | $ | 84,200 |  |  | $ | (78,725) |  |  | $ | 5,475 |
Balance at December 31, 2023 |  |  |  |  |
Coal supply agreement | $ | 84,200 |  |  | $ | (78,194) |  |  | $ | 6,006 |

Amortization expense for intangible assets was $0.5 million and $3.0 million in 2024 and 2023, respectively.
During 2023, we recorded a non-cash, long-lived asset impairment charge of $65.9 million. See Note 9 for further discussion of the impairment charge.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 7—Asset Retirement Obligations
Our obligations associated with the retirement of long-lived assets are recognized at fair value at the time the legal obligations are incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset and is depreciated either by the straight-line method or the units-of-production method. The liability is accreted each period until the liability is settled, at which time the liability is removed. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Our asset retirement obligations are principally for costs to close our consolidated surface mines and reclaim the land as a result of our normal mining activities. Management’s estimate involves a high degree of subjectivity. In particular, the obligation’s fair value is determined using a discounted cash flow technique and is based upon mining permit requirements and various assumptions including credit adjusted risk-free-rates, estimates of disturbed acreage, life of the mine, estimated reclamation costs, the application of various environmental laws and regulations and assumptions regarding equipment productivity. We review our asset retirement obligations at each mine site at least annually and makes necessary adjustments for permit changes and for revisions of estimates of the timing and extent of reclamation activities and cost estimates.
The accretion of the liability is being recognized over the estimated life of each individual asset retirement obligation and is recorded in the line Cost of sales in the accompanying Consolidated Statements of Operations. The associated asset is recorded in Property, Plant and Equipment, net in the accompanying Consolidated Balance Sheets. The depreciation of the asset is recorded in the line Cost of sales in the accompanying Consolidated Statements of Operations.
A reconciliation of our beginning and ending aggregate carrying amount of the asset retirement obligations are as follows:

|  | Coal Mining |  |  |  | Unallocated Items |  | NACCO Consolidated
Balance at January 1, 2023 |  | $ | 28,460 |  |  |  |  | $ | 17,542 |  |  | $ | 46,002 |
Liabilities incurred during the period |  | 1,920 |  |  |  |  | — |  |  | 1,920 |
Liabilities settled during the period |  | (852) |  |  |  |  | (1,048) |  |  | (1,900) |
Accretion expense |  | 2,170 |  |  |  |  | 1,358 |  |  | 3,528 |
Revision of estimated cash flows |  | 1,346 |  |  |  |  | 1,717 |  |  | 3,063 |
Balance at December 31, 2023 |  | $ | 33,044 |  |  |  |  | $ | 19,569 |  |  | $ | 52,613 |
Liabilities settled during the period |  | (6,115) |  |  |  |  | (960) |  |  | (7,075) |
Accretion expense |  | 2,530 |  |  |  |  | 1,510 |  |  | 4,040 |
Revision of estimated cash flows |  | 79 |  |  |  |  | (130) |  |  | (51) |
Balance at December 31, 2024 |  | $ | 29,538 |  |  |  |  | $ | 19,989 |  |  | $ | 49,527 |

During 2023, we acquired 100% of the membership interests in the Marshall Mine. We received $2.2 million of cash, assumed the asset retirement obligation estimated to be approximately $1.9 million and recognized a gain of approximately $0.3 million in the line Other, net in the accompanying Consolidated Statements of Operations. The asset retirement obligation’s fair value was determined using a discounted cash flow technique and is based upon permit requirements and various estimates and assumptions that would be used by market participants, including estimates of disturbed acreage, reclamation costs and assumptions regarding equipment productivity.
Bellaire's legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized. Bellaire’s asset retirement obligation is included in the table above in the Unallocated Items column.
Prior to 2023, Bellaire established a $5.0 million Mine Water Treatment Trust to provide a financial assurance mechanism in order to assure the long-term treatment of post-mining discharges. The fair value of Bellaire's Mine Water Treatment assets, which are recognized as a component of Equity securities on the Consolidated Balance Sheets, are $12.3 million and $11.2 million at December 31, 2024 and December 31, 2023, respectively, and are legally restricted for purposes of settling the Bellaire asset retirement obligation. See Note 9 for further discussion of the Mine Water Treatment Trust.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 8—Current and Long-Term Financing
Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of our subsidiaries.
The following table summarizes our available and outstanding borrowings:

| December 31
| 2024 |  | 2023
Total outstanding borrowings: |  |  |
Revolving credit agreement | $ | 70,000 |  |  | $ | 10,000 |
Other debt | 29,514 |  |  | 25,956 |
Total debt outstanding | $ | 99,514 |  |  | $ | 35,956 |
Current portion of borrowings outstanding | $ | 4,179 |  |  | $ | 13,953 |
Long-term portion of borrowings outstanding | 95,335 |  |  | 22,003 |
| $ | 99,514 |  |  | $ | 35,956 |
Total available borrowings, net of limitations, under revolving credit agreement | $ | 169,102 |  |  | $ | 115,120 |
Unused revolving credit agreement | $ | 99,102 |  |  | $ | 105,120 |
Weighted average stated interest rate on total borrowings | 6.4 | % |  | 6.6 | %

Annual maturities of total debt, excluding leases, are as follows:

2025 | 4,152 |
2026 | 8,700 |
2027 | 3,130 |
2028 | 72,925 |
2029 | 1,696 |
Thereafter | 8,827 |
| $ | 99,430 |

Interest paid on total debt was $5.3 million and $2.4 million during 2024 and 2023, respectively.
In September 2024, NACCO Natural Resources amended its secured revolving line of credit (Facility) to increase the revolving credit commitments to $200.0 million and extend the maturity to September 2028. Borrowings outstanding under the Facility were $70.0 million at December 31, 2024. At December 31, 2024, the excess availability under the Facility was $99.1 million, which reflects a reduction for outstanding letters of credit of $30.9 million.
The Facility has performance-based pricing, which sets interest rates based upon NACCO Natural Resources achieving various levels of debt to EBITDA ratios, as defined in the 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, 2024, for base rate and Term Secured Overnight Financing Rate loans were 1.50% and 2.50%, respectively. The Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.40% on the unused commitment at December 31, 2024. During the year ended December 31, 2024 and December 31, 2023, the average borrowing under the Facility was $27.2 million and $6.2 million, respectively, and the weighted-average annual interest rate, including the floating rate margin, was 8.83% and 6.06%, respectively.
The Facility contains restrictive covenants, which require, among other things, NACCO Natural Resources 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 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. At December 31, 2024, NACCO Natural Resources was in compliance with all financial covenants in the Facility.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The obligations under the Facility are guaranteed by certain of NACCO Natural Resources' direct and indirect, existing and future domestic subsidiaries, and is secured by certain assets of NACCO Natural Resources and the guarantors, subject to customary exceptions and limitations.
We have a demand note payable to Coteau, one of the unconsolidated subsidiaries, which bears interest based on the applicable quarterly federal short-term interest rate as announced from time to time by the IRS. At December 31, 2024 and 2023, the balance of the note was $7.7 million and $7.0 million and the interest rate was 4.15% and 5.12%, respectively.
We have ten notes payable that are secured by thirteen specified units of equipment, bear interest at a weighted average rate of 5.50%, and expire at various dates through 2030. One note includes a principal payment of $4.4 million at the end of the term on December 15, 2026. At December 31, 2024 and 2023, the outstanding balances of the notes payable were $21.8 million and $18.8 million, respectively.
NOTE 9—Fair Value Disclosure
Recurring Fair Value Measurements: The following table presents our assets accounted for at fair value on a recurring basis:

|  |  |  | Fair Value Measurements at Reporting Date Using
|  |  |  | Quoted Prices in |  |  |  | Significant
|  |  |  | Active Markets for |  | Significant Other |  | Unobservable
|  |  |  | Identical Assets |  | Observable Inputs |  | Inputs
Description |  | December 31, 2024 |  | (Level 1) |  | (Level 2) |  | (Level 3)
Assets: |  |  |  |  |  |  |  |
Equity securities |  | $ | 18,663 |  |  | $ | 18,663 |  |  | $ | — |  |  | $ | — |
|  | $ | 18,663 |  |  | $ | 18,663 |  |  | $ | — |  |  | $ | — |

|  |  |  | Fair Value Measurements at Reporting Date Using
|  |  |  | Quoted Prices in |  |  |  | Significant
|  |  |  | Active Markets for |  | Significant Other |  | Unobservable
|  |  |  | Identical Assets |  | Observable Inputs |  | Inputs
Description |  | December 31, 2023 |  | (Level 1) |  | (Level 2) |  | (Level 3)
Assets: |  |  |  |  |  |  |  |
Equity securities |  | $ | 17,208 |  |  | $ | 17,208 |  |  | $ | — |  |  | $ | — |
|  | $ | 17,208 |  |  | $ | 17,208 |  |  | $ | — |  |  | $ | — |

Bellaire's Mine Water Treatment Trust invests in available for sale securities that are reported at fair value based upon quoted market prices in active markets for identical assets; therefore, they are classified as Level 1 within the fair value hierarchy. The Mine Water Treatment Trust realized a gain of $1.5 million and $1.6 million in the years ended December 31, 2024 and 2023, respectively. See Note 7 for further discussion of Bellaire's Mine Water Treatment Trust.
Prior to 2023, we invested $2.0 million in equity securities of a public company with a diversified portfolio of royalty producing mineral interests. The investment is reported at fair value based upon quoted market prices in active markets for identical assets; therefore, it is classified as Level 1 within the fair value hierarchy. We recognized a gain of $0.3 million and $0.4 million in the years ended December 31, 2024 and 2023, respectively, related to the investment in these equity securities. The change in fair value of equity securities is reported on the line Gain on equity securities in the Other expense (income) section of the Consolidated Statements of Operations.
There were no transfers into or out of Levels 1, 2 or 3 during the year ended December 31, 2024.
Nonrecurring Fair Value Measurements: On December 18, 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We determined the reduction in customer demand
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
caused by this issue was an indicator of potential impairment as of December 31, 2023 and, as a result, reviewed MLMC's long-lived assets for impairment.
We assessed the recoverability of the MLMC asset group and determined that the assets were not fully recoverable when compared to the remaining future undiscounted cash flows from the asset group. As a result, we estimated the fair value of the asset group which resulted in a non-cash, long-lived asset impairment charge of $65.9 million. The asset impairment charge was recorded as Long-lived asset impairment charge in the Consolidated Statement of Operations for the year ended December 31, 2023. The $65.9 million relates exclusively to MLMC; however, $60.8 million and $5.1 million were recorded on the Coal Mining segment and the Minerals Management segment, respectively, as certain MLMC land assets were recorded within the Minerals Management segment. The impairment charge was allocated to the long-lived assets of the asset group on a pro rata basis using the relative carrying amount of those assets in relation to their fair value. The analysis for the land and real estate and other property, plant and equipment was calculated using market data for similar assets, which are classified as Level 2 inputs. The analysis of certain other long-term assets was calculated using unobservable inputs with little or no market data, which are classified as Level 3 inputs.
While the boiler issue at the customer's Red Hills Power Plant has been resolved, it resulted in a reduction in customer demand which had a significant impact on our results of operations during 2024. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries to partially offset losses related to the boiler outage.
Other Fair Value Measurement Disclosures: The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments. The fair values of revolving credit agreements and long-term debt, excluding finance leases, were determined using current rates offered for similar obligations taking into account subsidiary credit risk, which is Level 2 as defined in the fair value hierarchy. The fair value and the book value of revolving credit agreements and long-term debt, excluding finance leases, was $97.9 million and $99.4 million, respectively, at December 31, 2024 and $35.3 million and $35.8 million, respectively, at December 31, 2023.
Financial instruments that potentially subject us to concentration of credit risk consist principally of accounts receivable. Under our mining contracts, we recognize revenue and a related receivable as coal or other aggregates are delivered or predevelopment services are provided. These mining contracts provide for monthly settlements. Our significant credit concentration is uncollateralized; however, historically minimal credit losses have been incurred. To further reduce credit risk associated with accounts receivable, we perform periodic credit evaluations of our customers, but do not generally require advance payments or collateral.
NOTE 10—Leases
We recognize right-of-use assets (ROU assets) and lease liabilities for operating leases of real estate, mining and other equipment that expire at various dates through 2036. The majority of our leases are operating leases. NACCO does not recognize leases with a term of 12 months or less on the balance sheet. Instead, we recognize the related lease expense on a straight-line basis over the lease term. We account for lease and non-lease components as a single lease component. Our lease agreements do not contain lease payments that depend on an index or a rate, as such, minimum lease payments do not include variable lease payments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Leased assets and liabilities include the following at December 31:

Description | Location | 2024 | 2023 |  |  |
Assets |  |  |  |  |  |
Operating | Operating lease right-of-use assets | $ | 9,661 |  | $ | 8,667 |  |  |  |
Finance | Property, plant and equipment, net (a) | 79 |  | 107 |  |  |  |
Liabilities |  |  |  |  |  |
Current |  |  |  |  |  |
Operating | Other current liabilities | $ | 1,973 |  | $ | 1,485 |  |  |  |
Finance | Current maturities of long-term debt | 27 |  | 28 |  |  |  |
Non-current |  |  |  |  |  |
Operating | Operating lease liabilities | $ | 9,042 |  | $ | 8,782 |  |  |  |
Finance | Long-term debt | 57 |  | 84 |  |  |  |

(a) Finance leased assets are recorded net of accumulated amortization of less than $0.1 million as of December 31, 2024 and December 31, 2023.
The components of lease expense for the years ended December 31 are as follows:

Description | Location | 2024 | 2023
Lease expense |  |  |
Operating lease cost | Selling, general and administrative expenses | $ | 2,191 |  | $ | 1,712 |
Finance lease cost: |  |  |
Amortization of leased assets | Cost of sales | 28 |  | 61 |
Interest on lease liabilities | Interest expense | 8 |  | 7 |
Variable lease expense | Selling, general and administrative expenses | 955 |  | 572 |
Short-term lease expense | Selling, general and administrative expenses | 5,808 |  | 3,214 |
Total lease expense |  | $ | 8,990 |  | $ | 5,566 |

Future minimum finance and operating lease payments were as follows at December 31, 2024:

| Finance Leases |  | Operating Leases |  | Total
2025 | $ | 33 |  |  | $ | 2,769 |  |  | $ | 2,802 |
2026 | 33 |  |  | 2,441 |  |  | 2,474 |
2027 | 21 |  |  | 1,801 |  |  | 1,822 |
2028 | 9 |  |  | 1,822 |  |  | 1,831 |
2029 | — |  |  | 1,536 |  |  | 1,536 |
Subsequent to 2029 | — |  |  | 3,940 |  |  | 3,940 |
Total minimum lease payments | 96 |  |  | 14,309 |  |  | $ | 14,405 |
Amounts representing interest | 12 |  |  | 3,294 |  |  |
Present value of net minimum lease payments | $ | 84 |  |  | $ | 11,015 |  |  |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
As most of our leases do not provide an implicit rate, we determine the incremental borrowing rate based on the information available at the lease commencement date in determining the present value of lease payments. We consider our credit rating and the current economic environment in determining this collateralized rate. The assumptions used in accounting for ASC 842 for the years ended December 31 are as follows:

| 2024 | 2023
Weighted average remaining lease term (years) |  |
Operating | 6.70 | 6.81
Finance | 3.01 | 3.97
Weighted average discount rate |  |
Operating | 8.26 | % | 8.13 | %
Finance | 8.80 | % | 8.69 | %

The following table details cash paid for amounts included in the measurement of lease liabilities for the years ended December 31:

| 2024 | 2023
Operating cash flows from operating leases | $ | 2,509 |  | $ | 1,823 |
Operating cash flows from finance leases | 8 |  | 7 |
Financing cash flows from finance leases | 25 |  | 786 |

NOTE 11—Contingencies
Various legal and regulatory proceedings and claims have been or may be asserted against NACCO and certain subsidiaries relating to the conduct of their businesses. These proceedings and claims are incidental to the ordinary course of our business. Management believes that it has meritorious defenses and will vigorously defend us in these actions. Any costs that management estimates will be paid as a result of these claims are accrued when the liability is considered probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, we disclose the nature of the contingency and, in some circumstances, an estimate of the possible loss.
These matters are subject to inherent uncertainties, and unfavorable rulings could occur. If an unfavorable ruling were to occur, there exists the possibility of an adverse impact on our financial position, results of operations and cash flows of the period in which the ruling occurs, or in future periods.
NOTE 12—Stockholders' Equity and Earnings Per Share
NACCO Industries, Inc. Class A common stock is traded on the New York Stock Exchange under the ticker symbol NC. Because of transfer restrictions on Class B common stock, no trading market has developed, or is expected to develop, for our Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis at any time at the request of the holder. Our Class A common stock and Class B common stock have the same cash dividend rights per share. As the liquidation and dividend rights are identical, any distribution of earnings would be allocated to Class A and Class B stockholders on a proportionate basis, and accordingly the net income per share for each class of common stock is identical. The Class A common stock has one vote per share and the Class B common stock has ten votes per share. The total number of authorized shares of Class A common stock and Class B common stock at December 31, 2024 was 25,000,000 shares and 6,756,176 shares, respectively. Treasury shares of Class A common stock totaling 2,488,013 and 2,335,178 at December 31, 2024 and 2023, respectively, have been deducted from shares outstanding.
Stock Repurchase Program: On November 7, 2023, our Board of Directors approved a stock purchase program (2023 Stock Repurchase Program) providing for the purchase of up to $20.0 million of our outstanding Class A common stock through
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
December 31, 2025. NACCO's previous repurchase program (2021 Stock Repurchase Program) would have expired on December 31, 2023 but was terminated and replaced by the 2023 Stock Repurchase Program. During 2024, we repurchased 316,950 shares of Class A Common Stock under the 2023 Stock Repurchase Program for an aggregate purchase price of $9.9 million. During 2023, we repurchased 47,095 shares of Class A Common Stock under the 2021 Stock Repurchase Program for an aggregate purchase price of $1.6 million and 43,872 shares of Class A Common Stock under the 2023 Stock Repurchase Program for an aggregate purchase price of $1.5 million.
The timing and amount of any repurchases under the 2023 Stock Repurchase Program are determined at the discretion of our management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for our Class A common stock and other legal and contractual restrictions. The 2023 Stock Repurchase Program does not require us to acquire any specific number of shares and may be modified, suspended, extended or terminated by us without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise. All or part of the repurchases under the 2023 Stock Repurchase Program may be implemented under a Rule 10b5-1 trading plan, which would allow repurchases under pre-set terms at times when we might otherwise be restricted from doing so under applicable securities laws.
Stock Compensation: See Note 2 for a discussion of our restricted stock awards.
Earnings per Share: The weighted average number of shares of Class A common stock and Class B common stock outstanding used to calculate basic and diluted earnings per share were as follows:

| 2024 |  | 2023
Basic weighted average shares outstanding | 7,363 |  |  | 7,478 |
Dilutive effect of restricted stock awards | 48 |  |  | N/A
Diluted weighted average shares outstanding | 7,411 |  |  | 7,478 |
Basic earnings (loss) per share | $ | 4.58 |  |  | $ | (5.29) |
Diluted earnings (loss) per share | $ | 4.55 |  |  | $ | (5.29) |

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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
NOTE 13—Income Taxes
We provide for income taxes and the related accounts under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when management determines it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.
The components of Income (loss) before income tax benefit and the Income tax benefit for the years ended December 31 are as follows:

| 2024 |  | 2023
Income (loss) before income tax benefit |  |  |
Domestic | $ | 33,637 |  |  | $ | (64,077) |
Foreign | 9 |  |  | (81) |
| $ | 33,646 |  |  | $ | (64,158) |
Income tax benefit |  |  |
Current income tax provision (benefit): |  |  |
Federal | $ | (2,520) |  |  | $ | (3,405) |
State | 906 |  |  | 290 |
Foreign | 2 |  |  | (342) |
Total current | (1,612) |  |  | (3,457) |
Deferred income tax provision (benefit): |  |  |
Federal | 1,373 |  |  | (16,467) |
State | 144 |  |  | (4,647) |
Total deferred | 1,517 |  |  | (21,114) |
| $ | (95) |  |  | $ | (24,571) |

We made income tax payments of $5.2 million and $1.4 million during 2024 and 2023, respectively. During the same periods, income tax refunds totaled $1.0 million and $14.9 million, respectively.
The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before the provision for income taxes. A reconciliation of the federal statutory and effective income tax rate for the years ended December 31 is as follows:

| 2024 |  | 2023
Income (loss) before income tax benefit | $ | 33,646 |  |  | $ | (64,158) |
Statutory taxes at 21.0% | $ | 7,066 |  |  | $ | (13,473) |
State and local income taxes | 556 |  |  | (4,392) |
Non-deductible expenses | 927 |  |  | 1,071 |
Percentage depletion | (4,683) |  |  | (3,455) |
R&D and other federal credits | (796) |  |  | (109) |
Settlements and uncertain tax positions | (2,273) |  |  | (3,512) |
Other, net | (892) |  |  | (701) |
Income tax benefit | $ | (95) |  |  | $ | (24,571) |
Effective income tax rate | (0.3) | % |  | 38.3 | %

We recorded an income tax benefit of $0.1 million for the year ended December 31, 2024 on income before income tax of $33.6 million, or 0.3%, compared to an income tax benefit of $24.6 million on loss before income tax of $64.2 million, or 38.3%, for the year ended December 31, 2023. The years ended December 31, 2024 and 2023 both included $4.0 million of discrete tax benefits, primarily from the reversal of uncertain tax provisions. Excluding the $4.0 million of discrete tax benefits in each year, the effective income tax rate in 2024 and 2023 was 11.5% and 32.0%, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The change in the effective income tax rate for 2024 compared to 2023, excluding the impact of the long-lived asset impairment charge and discrete items, is primarily due to an increase in earnings at entities that do not qualify for percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where income or loss before income tax is relatively small, the proportional effect of the benefit from percentage depletion on the effective tax rate may be significant. When income tax expense is recorded, the benefit from percentage depletion decreases the effective income tax rate, while the effect is to increase the effective income tax rate when a benefit for income taxes is recorded.
A detailed summary of the total deferred tax assets and liabilities in our Consolidated Balance Sheets resulting from differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes is as follows:

| December 31
| 2024 |  | 2023
Deferred tax assets |  |  |
Lease liabilities | $ | 1,252 |  |  | $ | 7,083 |
Tax carryforwards | 12,371 |  |  | 14,816 |
Inventories | 6,029 |  |  | 4,880 |
Accrued liabilities | 9,430 |  |  | 9,226 |
Employee benefits | 3,630 |  |  | 3,319 |
Land valuation adjustment | 6,489 |  |  | 6,378 |
Partnership investment - development costs | 14,819 |  |  | 12,565 |
Other | 7,866 |  |  | 9,680 |
Total deferred tax assets | 61,886 |  |  | 67,947 |
Less: Valuation allowance | 11,672 |  |  | 11,783 |
| 50,214 |  |  | 56,164 |
Deferred tax liabilities |  |  |
Lease right-of-use assets | 1,209 |  |  | 7,429 |
Depreciation and depletion | 23,731 |  |  | 23,607 |
Accrued pension benefits | 10,633 |  |  | 10,047 |
Total deferred tax liabilities | 35,573 |  |  | 41,083 |
Net deferred asset | $ | 14,641 |  |  | $ | 15,081 |

The following table summarizes the tax carryforwards and associated carryforward periods and related valuation allowances where we have determined that realization is uncertain:

| December 31, 2024
| Net deferred tax asset |  | Valuation allowance |  | Carryforwards expire during:
State net operating loss | $ | 15,584 |  |  | $ | 14,610 |  |  | 2025 - 2044

| December 31, 2023
| Net deferred tax asset |  | Valuation allowance |  | Carryforwards expire during:
State net operating loss | $ | 16,526 |  |  | $ | 14,757 |  |  | 2024-2043

We have a valuation allowance for certain state and foreign deferred tax assets. Based upon the review of historical earnings and the relevant expiration of carryforwards, including utilization limitations in the various state taxing jurisdictions, we believe the valuation allowances are appropriate and do not expect to release valuation allowances within the next twelve months that would have a significant effect on our financial position or results of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Since 2021, we have participated in a voluntary program with the IRS called Compliance Assurance Process (CAP). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return. In general, we operate in taxing jurisdictions that provide a statute of limitations period ranging from three to five years for the taxing authorities to review the applicable tax filings. Our tax returns are under routine examination by various taxing authorities. We have not been informed of any material assessment for which an accrual has not been previously provided and would vigorously contest any material assessment. Management believes any potential adjustment would not materially affect our financial condition or results of operations.
The following is a reconciliation of our total gross unrecognized tax benefits, defined as the aggregate tax effect of differences between tax return positions and the benefits recognized in the financial statements for the years ended December 31, 2024 and 2023. Approximately $0.6 million and $2.8 million of the gross unrecognized tax benefits as of December 31, 2024 and 2023, respectively, relate to permanent items that, if recognized, would impact the effective income tax rate. This amount differs from the gross unrecognized tax benefits presented in the table below due to (1) the deferred tax asset which would be available if the position were not sustained upon audit and (2) the decrease in U.S. federal income taxes which would occur upon the recognition of the state tax benefits included herein.

| 2024 |  | 2023 |  |
Balance at January 1 | $ | 6,148 |  |  | $ | 9,626 |  |  |
Decreases based on lapse of applicable statute of limitations | (5,396) |  |  | (3,478) |  |  |
Balance at December 31 | $ | 752 |  |  | $ | 6,148 |  |  |

We record interest and penalties on uncertain tax positions as a component of the income tax provision. We recognized a net benefit of less than $0.1 million in interest and penalties related to uncertain tax positions during 2024 and 2023. The total amount of interest and penalties accrued was $0.2 million as of December 31, 2024 and 2023.
We expect the amount of unrecognized tax benefits will change within the next 12 months; however, the change is not expected to have a significant effect on our financial position, results of operations or cash flows.
NOTE 14—Retirement Benefit Plans
Defined Benefit Plans: We maintain defined benefit pension plans that provide benefits based on years of service and average compensation during certain periods. Prior to 2023, we amended the Combined Plan to freeze pension benefits for all employees. We also amended the Supplemental Retirement Benefit Plan (SERP) to freeze all pension benefits. All of our eligible employees, including employees whose pension benefits are frozen, receive retirement benefits under defined contribution retirement plans.
During 2023, our Board of Directors approved the termination of the Combined Plan and participants were offered lump-sum distributions as part of the termination process. As a result of the lump-sum distributions, we recognized a non-cash, pension settlement charge of $1.8 million on the Other, net line within the accompanying Consolidated Statements of Operations. The $1.8 million charge represents a pro rata portion of the unrecognized net loss recorded in Accumulated other comprehensive loss.
The assumptions used in accounting for the defined benefit plans were as follows for the years ended December 31:

| 2024 |  | 2023 |  |
Weighted average discount rates for pension benefit obligation | 5.39% - 5.49% |  | 5.02% - 5.04% |  |
Weighted average discount rates for net periodic benefit cost | 5.02% - 5.04% |  | 5.36% - 5.40% |  |
Expected long-term rate of return on assets for net periodic benefit cost | 5.00% |  | 7.00% |  |

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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Set forth below is detail of the net periodic pension expense for the defined benefit plans for the years ended December 31:

| 2024 |  | 2023 |  |
Interest cost | $ | 1,360 |  |  | $ | 1,639 |  |  |
Expected return on plan assets | (1,641) |  |  | (2,751) |  |  |
Amortization of actuarial loss | 270 |  |  | 51 |  |  |
Amortization of prior service cost | 58 |  |  | 58 |  |  |
Settlements | — |  |  | 1,815 |  |  |
Net periodic pension expense | $ | 47 |  |  | $ | 812 |  |  |

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive loss for the years ended December 31:

| 2024 |  | 2023 |  |
Current year actuarial loss | $ | 960 |  |  | $ | 2,560 |  |  |
Amortization of actuarial loss | (270) |  |  | (51) |  |  |
Amortization of prior service cost | (58) |  |  | (58) |  |  |
Settlements | — |  |  | (1,815) |  |  |
Total recognized in other comprehensive loss | $ | 632 |  |  | $ | 636 |  |  |

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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The following table sets forth the changes in the benefit obligation and the plan assets during the year and the funded status of the defined benefit plans at December 31:

| 2024 | 2023
Change in benefit obligation |  |  |
Projected benefit obligation at beginning of year | $ | 28,357 |  |  | $ | 31,722 |
Interest cost | 1,360 |  |  | 1,639 |
Actuarial (gain) loss | (427) |  |  | 2,261 |
Benefits paid | (2,610) |  |  | (2,614) |
Settlements | — |  |  | (4,651) |
Projected benefit obligation at end of year | $ | 26,680 |  |  | $ | 28,357 |
Accumulated benefit obligation at end of year | $ | 26,680 |  |  | $ | 28,357 |
Change in plan assets |  |  |
Fair value of plan assets at beginning of year | $ | 30,128 |  |  | $ | 34,485 |
Actual return on plan assets | 258 |  |  | 2,452 |
Employer contributions | 475 |  |  | 456 |
Benefits paid | (2,610) |  |  | (2,614) |
Settlements | — |  |  | (4,651) |
Fair value of plan assets at end of year | $ | 28,251 |  |  | $ | 30,128 |
Funded status at end of year | $ | 1,571 |  |  | $ | 1,771 |
Amounts recognized in the balance sheets consist of: |  |  |
Non-current assets | $ | 5,624 |  |  | $ | 6,068 |
Current liabilities | (515) |  |  | (510) |
Non-current liabilities | (3,538) |  |  | (3,787) |
| $ | 1,571 |  |  | $ | 1,771 |
Components of accumulated other comprehensive loss consist of: |  |  |
Actuarial loss | $ | 12,072 |  |  | $ | 11,379 |
Prior service cost | 528 |  |  | 586 |
Deferred taxes | (2,869) |  |  | (2,724) |
| $ | 9,731 |  |  | $ | 9,241 |

We recognize as a component of benefit (income) cost, as of the measurement date, any unrecognized actuarial net gains or losses that exceed 10% of the larger of the projected benefit obligations or the plan assets, defined as the corridor. Amounts outside the corridor are amortized over the average expected remaining service of active participants expected to benefit under the retiree medical plans or over the average expected remaining lifetime of inactive participants for the pension plans. The (gain) loss amounts recognized in AOCI are not expected to be fully recognized until the plan is terminated or as settlements occur, which would trigger accelerated recognition. Prior service costs resulting from plan changes are also in AOCI.
Our policy is to make contributions to fund our pension plans within the range allowed by applicable regulations.
We maintain one supplemental defined benefit plan that pays monthly benefits to participants directly out of corporate funds. All other pension benefit payments are made from assets of the pension plans.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Future pension benefit payments expected to be paid from assets of the pension plans are:

2025 | $ | 2,750 |
2026 | 2,631 |
2027 | 2,575 |
2028 | 2,514 |
2029 | 2,435 |
2030 - 2034 | 10,860 |
| $ | 23,765 |

The expected long-term rate of return on defined benefit plan assets reflects management's expectations of long-term rates of return on funds invested to provide for benefits included in the projected benefit obligations. In establishing the expected long-term rate of return assumption for plan assets, we consider the historical rates of return over a period of time that is consistent with the long-term nature of the underlying obligations of these plans as well as a forward-looking rate of return. The historical and forward-looking rates of return for each of the asset classes used to determine our estimated rate of return assumption were based upon the rates of return earned or expected to be earned by investments in the equivalent benchmark market indices for each of the asset classes.
Expected returns for pension plans are based on a calculated market-related value for pension plan assets. Under this methodology, asset gains and losses resulting from actual returns that differ from our expected returns are recognized in the market-related value of assets ratably over three years.
The pension plans maintain investment policies that, among other things, establish a portfolio asset allocation methodology with percentage allocation bands for individual asset classes. The investment policies provide that investments are reallocated between asset classes as balances exceed or fall below the appropriate allocation bands.
The following is the actual allocation percentage and target allocation percentage for the pension plan assets at December 31:

| 2024 Actual Allocation |  | 2023 Actual Allocation |  | Target Allocation Range
Fixed income securities | 99.2 | % |  | 99.1 | % |  | 90.0% - 100.0%
Money market funds | 0.8 | % |  | 0.6 | % |  | 0.0% - 10.0%
Cash equivalents | — | % |  | 0.3 | % |  | 0.0%

The asset allocation reflects the move into fixed income securities to mitigate volatility prior to the termination of the Combined Plan, currently expected to occur in 2025.
The defined benefit pension plans do not have any direct ownership of NACCO common stock.
The fair value of each major category of our pension plan assets are valued using quoted market prices in active markets for identical assets, or Level 1 in the fair value hierarchy. Following are the values as of December 31:

| Level 1
| 2024 |  | 2023
Fixed income securities | $ | 28,028 |  |  | $ | 29,866 |
Money market funds | 223 |  |  | 181 |
Cash equivalents | — |  |  | 81 |
Total | $ | 28,251 |  |  | $ | 30,128 |

Postretirement Health Care: We also maintain health care plans which provide benefits to grandfathered eligible retired employees. All of our health care plans have a cap on our share of the costs. The health care plans have network provided benefits which result in cost savings for us. These plans have no assets. Under our current policy, plan benefits are funded at the time they are due to participants.
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The assumptions used in accounting for the postretirement health care plans are set forth below for the years ended December 31:

| 2024 |  | 2023 |  |
Weighted average discount rates for benefit obligation | 5.26 | % |  | 4.98 | % |  |
Weighted average discount rates for net periodic benefit cost | 4.98 | % |  | 5.29 | % |  |
Health care cost trend rate assumed for next year | 6.50% |  | 6.25% - 6.50% |  |
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 4.75% |  | 4.75% |  |
Year that the rate reaches the ultimate trend rate | 2033 |  | 2029 - 2033 |  |

Set forth below is detail of the net periodic benefit expense for the postretirement health care plans for the years ended December 31:

| 2024 |  | 2023 |  |
Service cost | $ | 8 |  |  | $ | 7 |  |  |
Interest cost | 75 |  |  | 77 |  |  |
Amortization of actuarial loss | 75 |  |  | 44 |  |  |
Amortization of prior service credit | (6) |  |  | (50) |  |  |
Net periodic benefit expense | $ | 152 |  |  | $ | 78 |  |  |

Set forth below is detail of other changes in benefit obligations recognized in other comprehensive (income) loss for the years ended December 31:

| 2024 |  | 2023 |  |
Current year actuarial (gain) loss | $ | (49) |  |  | $ | 173 |  |  |
Amortization of actuarial loss | (75) |  |  | (44) |  |  |
Amortization of prior service credit | 6 |  |  | 50 |  |  |
Total recognized in other comprehensive (income) loss | $ | (118) |  |  | $ | 179 |  |  |

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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The following sets forth the changes in benefit obligations during the year and the funded status of the postretirement health care plans at December 31:

| 2024 |  | 2023
Change in benefit obligation |  |  |
Benefit obligation at beginning of year | $ | 1,579 |  |  | $ | 1,551 |
Service cost | 8 |  |  | 7 |
Interest cost | 75 |  |  | 77 |
Actuarial (gain) loss | (49) |  |  | 173 |
Benefits paid | (195) |  |  | (229) |
Benefit obligation at end of year | $ | 1,418 |  |  | $ | 1,579 |
Funded status at end of year | $ | (1,418) |  |  | $ | (1,579) |
Amounts recognized in the balance sheets consist of: |  |  |
Current liabilities | $ | (169) |  |  | $ | (183) |
Noncurrent liabilities | (1,249) |  |  | (1,396) |
| $ | (1,418) |  |  | $ | (1,579) |
Components of accumulated other comprehensive loss consist of: |  |  |
Actuarial loss | $ | 416 |  |  | $ | 542 |
Prior service credit | — |  |  | (6) |
Deferred taxes | (95) |  |  | (123) |
| $ | 321 |  |  | $ | 413 |

Future postretirement health care benefit payments expected to be paid are:

2025 | 173 |
2026 | 182 |
2027 | 185 |
2028 | 174 |
2029 | 166 |
2030 - 2034 | 582 |
| $ | 1,462 |

Defined Contribution Plans: We maintain a defined contribution (401(k)) plan for substantially all employees and provide employer matching contributions based on plan provisions. The plan also provides for a minimum employer contribution. Our matching contributions for these plans were $3.6 million and $3.6 million in 2024 and 2023, respectively.
NOTE 15—Business Segments
Our operating segments are: (i) Coal Mining, (ii) NAMining and (iii) Minerals Management. We determine our reportable segments by first identifying our operating segments, and then by assessing whether any components of these segments constitute a business for which discrete financial information is available and where segment management regularly reviews the operating results of that component. Our President and Chief Executive Officer, who is the CODM, utilizes Operating profit (loss) to evaluate segment performance and allocate resources. Our CODM considers actual, budgeted and forecasted Operating profit (loss) from operations on a monthly basis for evaluating the performance of each segment and making decisions about allocating capital and other resources to each segment.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
See Note 1 for additional discussion of our reportable segments. All current operations reside in the U.S. The accounting policies of the reportable segments are described in Note 2.
In 2024 and 2023, three customers and two customers, respectively, accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:

|  |  | Percentage of Consolidated Revenue
| Segment |  | 2024 |  | 2023
| Coal Mining customer |  | 29 | % |  | 40 | %
| NAMining customer |  | 24 | % |  | 22 | %
| NAMining customer |  | 11 | % |  | 7 | %

The following tables provide segment financial information and a reconciliation of segment results to consolidated results for the years ended December 31:

| 2024 |  | 2023 |  |
Revenues |  |  |  |  |
Coal Mining | $ | 68,611 |  |  | $ | 85,415 |  |  |
NAMining | 119,600 |  |  | 90,532 |  |  |
Minerals Management | 34,579 |  |  | 32,985 |  |  |
Unallocated Items | 17,707 |  |  | 8,459 |  |  |
Eliminations | (2,789) |  |  | (2,597) |  |  |
Total | $ | 237,708 |  |  | $ | 214,794 |  |  |
Cost of sales |  |  |  |  |
Coal Mining | $ | 79,375 |  |  | $ | 108,760 |  |  |
NAMining | 110,821 |  |  | 83,719 |  |  |
Minerals Management | 5,234 |  |  | 3,969 |  |  |
Unallocated Items | 15,323 |  |  | 6,252 |  |  |
Eliminations | (2,801) |  |  | (2,497) |  |  |
Total | $ | 207,952 |  |  | $ | 200,203 |  |  |
Earnings of unconsolidated operations |  |  |  |  |
Coal Mining | $ | 51,821 |  |  | $ | 44,633 |  |  |
NAMining | 5,010 |  |  | 5,361 |  |  |
Minerals Management | 647 |  |  | — |  |  |
Unallocated Items | (2) |  |  | — |  |  |
Total | $ | 57,476 |  |  | $ | 49,994 |  |  |
Operating expenses* |  |  |  |  |
Coal Mining | $ | 30,358 |  |  | $ | 92,630 |  |  |
NAMining | 8,017 |  |  | 8,826 |  |  |
Minerals Management | 1,065 |  |  | 9,598 |  |  |
Unallocated Items | 25,699 |  |  | 23,668 |  |  |
Total | $ | 65,139 |  |  | $ | 134,722 |  |  |

*Operating expenses consist of Selling, general and administrative expenses, Amortization of intangible assets, (Gain) loss on sale of assets and Long-lived asset impairment charges.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)

| 2024 |  | 2023 |  |
Operating profit (loss) |  |  |  |  |
Coal Mining | $ | 24,311 |  |  | $ | (71,342) |  |  |
NAMining | 5,772 |  |  | 3,348 |  |  |
Minerals Management | 28,927 |  |  | 19,418 |  |  |
Unallocated Items | (23,317) |  |  | (21,461) |  |  |
Eliminations | 12 |  |  | (100) |  |  |
Total | $ | 35,705 |  |  | $ | (70,137) |  |  |
Expenditures for property, plant and equipment and acquisition of mineral interests |  |  |  |  |
Coal Mining | $ | 8,292 |  |  | $ | 6,609 |  |  |
NAMining | 30,556 |  |  | 36,073 |  |  |
Minerals Management | 1,079 |  |  | 38,881 |  |  |
Unallocated Items | 15,492 |  |  | 559 |  |  |
Total | $ | 55,419 |  |  | $ | 82,122 |  |  |
Depreciation, depletion and amortization |  |  |  |  |
Coal Mining | $ | 9,476 |  |  | $ | 17,569 |  |  |
NAMining | 9,811 |  |  | 8,172 |  |  |
Minerals Management | 4,273 |  |  | 3,067 |  |  |
Unallocated Items | 1,092 |  |  | 579 |  |  |
Total | $ | 24,652 |  |  | $ | 29,387 |  |  |

Asset information by segment is not discretely maintained for internal reporting or used in evaluating performance.
NOTE 16—Unconsolidated Subsidiaries
Each of our wholly owned Unconsolidated Subsidiaries, within the Coal Mining and NAMining segments, meet the definition of a VIE. The Unconsolidated Subsidiaries are capitalized primarily with debt financing provided by or supported by their respective customers, and generally without recourse to us. Although we own 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, we have determined that the equity capital provided by us is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct the activities that most significantly affect the economic performance of the entities. As a result, we are not the primary beneficiary and therefore do not consolidate these entities' financial positions or results of operations. See Note 1 for a discussion of these entities.
The Investment in the unconsolidated subsidiaries and related tax positions totaled $14.1 million and $12.4 million at December 31, 2024 and 2023, respectively. Our risk of loss relating to these entities is limited to our invested capital, which was $5.5 million and $5.0 million at December 31, 2024 and 2023, respectively.
NACCO Natural Resources is a party to certain guarantees related to Coyote Creek. Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (LSA), NACCO Natural Resources 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 by Coyote Creek’s customers, NACCO Natural Resources is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. To date, no payments have been required from NACCO Natural Resources since the inception of these guarantees. We believe that the likelihood NACCO Natural Resources would be required to perform under the guarantees is remote, and no amounts related to these guarantees have been recorded.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
Summarized financial information for the unconsolidated subsidiaries is as follows:

| 2024 |  | 2023
Statement of Operations |  |  |
Revenue | $ | 542,643 |  |  | $ | 610,734 |
Gross profit | $ | 60,256 |  |  | $ | 63,646 |
Income before income taxes | $ | 56,831 |  |  | $ | 49,994 |
Net income | $ | 49,284 |  |  | $ | 43,714 |
Balance Sheet |  |  |
Current assets | $ | 145,655 |  |  | $ | 124,387 |
Non-current assets | $ | 816,430 |  |  | $ | 814,226 |
Current liabilities | $ | 158,591 |  |  | $ | 161,606 |
Non-current liabilities | $ | 798,043 |  |  | $ | 772,003 |

Revenue includes all mine operating costs that are reimbursed by the customers of the Unconsolidated Subsidiaries as well as the compensation per ton of coal, heating unit (MMBtu) or ton of limestone delivered. Reimbursed costs have offsetting expenses and have no impact on income before income taxes. Income before income taxes represents the Earnings of the unconsolidated operations within the Coal Mining and NAMining segments.
We received dividends of $48.8 million and $45.8 million from the Unconsolidated Subsidiaries in 2024 and 2023, respectively.
NOTE 17—Supplemental Oil and Gas Disclosures (Unaudited)
The Minerals Management segment derives income primarily by leasing our 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. As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. See Note 1, Note 2 and Note 15 for additional discussion of the Minerals Management segment.
Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and gas royalty and mineral interests with applicable accumulated depreciation, depletion and amortization at December 31 are as follows:

| 2024 |  | 2023 |  |
Proved developed | $ | 16,720 |  |  | $ | 16,179 |  |  |
Proved undeveloped | 52,428 |  |  | 51,971 |  |  |
Proved reserves | 69,148 |  |  | 68,150 |  |  |
Less: accumulated depreciation, depletion and amortization | 6,061 |  |  | 3,309 |  |  |
Net royalty interests in oil and natural gas properties | $ | 63,087 |  |  | $ | 64,841 |  |  |

Oil and Natural Gas Reserves
Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to Company interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. 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. All reserves estimates have
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.
The following table presents our estimated net proved oil and natural gas reserves as of December 31 based on the reserve report prepared by Haas & Cobb Petroleum Consultants, our independent petroleum engineering firm. All of our reserves are located in the United States.

|  | Net reserves as of December 31, 2024
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2)
Proved developed |  | 620,790 |  |  | 443,650 |  |  | 27,491,840 |
Proved undeveloped |  | 74,400 |  |  | 30,280 |  |  | 135,830 |
Total |  | 695,190 |  |  | 473,930 |  |  | 27,627,670 |

|  | Net reserves as of December 31, 2023
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2)
Proved developed |  | 656,370 |  |  | 380,650 |  |  | 23,596,110 |
Proved undeveloped |  | 9,020 |  |  | 3,720 |  |  | 26,420 |
Total |  | 665,390 |  |  | 384,370 |  |  | 23,622,530 |

(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.
Estimated Proved Reserves
The following table summarizes changes in proved reserves during the year ended December 31, 2024:

|  | Estimated Proved Reserves
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2) |
December 31, 2023 |  | 665,390 |  |  | 384,370 |  |  | 23,622,530 |  |
Purchases |  | 14,005 |  |  | 1,233 |  |  | 29,268 |  |
Extensions and discoveries |  | 236,491 |  |  | 85,087 |  |  | 7,040,710 |  |
Revisions of previous estimates (3) |  | (105,479) |  |  | 63,441 |  |  | (498,627) |  |
Production |  | (32,077) |  |  | (15,687) |  |  | (1,843,911) |  |
Other |  | (83,140) |  |  | (44,514) |  |  | (722,300) |  |
December 31, 2024 |  | 695,190 |  |  | 473,930 |  |  | 27,627,670 |  |

Estimated Proved Undeveloped Reserves (PUDs)
The following table summarizes changes in PUDs during the year ended December 31, 2024:

|  | Estimated Proved Undeveloped Reserves
|  | Oil (bbl) (1) |  | NGL (bbl) (1) |  | Residue gas (Mcf) (2) |
December 31, 2023 |  | 9,020 |  |  | 3,720 |  |  | 26,420 |  |
Purchases |  | 2,208 |  |  | 38 |  |  | 5,237 |  |
Extensions and discoveries |  | 69,716 |  |  | 27,902 |  |  | 126,724 |  |
Conversions |  | (3,322) |  |  | (1,914) |  |  | (10,017) |  |
Revisions of previous estimates (3) |  | (3,222) |  |  | 534 |  |  | (12,534) |  |
December 31, 2024 |  | 74,400 |  |  | 30,280 |  |  | 135,830 |  |

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.
(3) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
As an owner of mineral and royalty interests, we generally do not have evidence of approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2024, PUD reserves consists of 89 wells in various stages of drilling or completions. As of December 31, 2024, less than 1% of our total proved reserves were classified as PUDs.
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. Future cash inflows are computed by applying applicable prices relating to proved reserves to the year-end quantities of those reserves. Future production and costs are derived based on current costs assuming continuation of existing economic conditions. Federal income tax expenses are deducted from future production revenues in the calculation of the standardized measure using the statutory tax rate. We are subject to certain state-based taxes; however, these amounts are not material. The projections should not be viewed as realistic estimates of future cash flows, nor should the standardized measure be interpreted as representing current value to us. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.
The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2024:

|  | Gross Amounts |  | Statutory tax rate |  | Net Amounts
Future cash inflows(3) |  | $ | 119,534 |  |  |  |  |
Future production costs |  | 33,308 |  |  |  |  |
Future net cash flows before income tax expense |  | 86,226 |  |  | 21 | % |  | 68,119 |
10% discount to reflect timing of cash flows |  | (32,580) |  |  | 21 | % |  | (25,739) |
Standardized measure of discounted cash flows |  | $ | 53,646 |  |  | 21 | % |  | $ | 42,380 |

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2023:

|  | Gross Amounts |  | Statutory tax rate |  | Net Amounts
Future cash inflows(3) |  | $ | 122,286 |  |  |  |  |
Future production costs |  | 27,487 |  |  |  |  |
Future net cash flows before income tax expense |  | 94,799 |  |  | 21 | % |  | 74,891 |
10% discount to reflect timing of cash flows |  | (33,521) |  |  | 21 | % |  | (26,481) |
Standardized measure of discounted cash flows |  | $ | 61,278 |  |  | 21 | % |  | 48,410 |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows during 2024:

|  | Gross amounts |  |
|  | 2024 |  | 2023 |  |  |
January 1 |  | $ | 61,278 |  |  | $ | 116,526 |  |  |  |
Purchases |  | 522 |  |  | 11,312 |  |  |  |
Extensions and discoveries |  | 18,426 |  |  | 11,419 |  |  |  |
Revisions of previous estimates (3)(4) |  | (20,713) |  |  | (61,206) |  |  |  |
Conversions |  | (5,867) |  |  | (16,773) |  |  |  |
December 31 |  | $ | 53,646 |  |  | $ | 61,278 |  |  |  |

(3) Requirements for oil and gas reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The benchmark price for WTI crude oil sold at Cushing, OK during 2024 and 2023 was $75.48 and $78.22 per bbl, respectively. The benchmark price for natural gas delivered at Henry Hub during 2024 and 2023 was $2.13 and $2.64 per MMBTU, respectively. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
(4) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
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SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, 2024 AND 2023

|  |  |  | Additions |  |  |  |  |  |
Description |  | Balance at Beginning of Period |  | Charged to Costs and Expenses |  | Charged to Other Accounts — Describe |  | Deductions — Describe |  | Balance at End of Period (A)
(In thousands)
2024 |  |  |  |  |  |  |  |  |  |  |  |
Reserves deducted from asset accounts: |  |  |  |  |  |  |  |  |  |  |  |
Deferred tax valuation allowances |  | $ | 11,783 |  |  | $ | (111) |  |  | $ | — |  |  | $ | — |  |  |  |  | $ | 11,672 |
2023 |  |  |  |  |  |  |  |  |  |  |  |
Reserves deducted from asset accounts: |  |  |  |  |  |  |  |  |  |  |  |
Deferred tax valuation allowances |  | $ | 11,809 |  |  | $ | (26) |  |  | $ | — |  |  | $ | — |  |  |  |  | $ | 11,783 |

(A)Balances which are not required to be presented and those which are immaterial have been omitted.
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