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nacco-20251231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2025

Commission File No. 1-9172

NACCO INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

(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

Class A Common Stock, $1 par value per share NC NYSE Texas

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 ̈Noþ

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 ̈Noþ

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. Yesþ 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).

Yesþ 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.

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, 2025 (the last business day of the registrant's most recently completed second fiscal quarter): $118,562,800

Number of shares of Class A Common Stock outstanding at February 27, 2026: 5,971,635

Number of shares of Class B Common Stock outstanding at February 27, 2026: 1,562,953

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for its 2026 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 15

Item 1B. UNRESOLVED STAFF COMMENTS 23

Item 1C. CYBERSECURITY 24

Item 2. PROPERTIES 25

Item 3. LEGAL PROCEEDINGS 44

Item 4. MINE SAFETY DISCLOSURES 44

PART II.

Item 6. [RESERVED] 45

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 59

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 59

Item 9A. CONTROLS AND PROCEDURES 59

Item 9B. OTHER INFORMATION 59

Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 59

PART III.

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 60

Item 11. EXECUTIVE COMPENSATION 60

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 60

PART IV.

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 61

SIGNATURES 67

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 reportable business segments: Utility Coal Mining, Contract Mining and Minerals and Royalties. The Utility Coal Mining segment, operated by North American Coal®, manages surface coal mines that are exclusive, long-term fuel providers for power generation companies. The Contract Mining segment, operated by North American Mining®, is a leading provider of a broad range of specialized, long-term contract mining services. The Minerals and Royalties segment, which includes the Catapult Mineral Partners® (Catapult) business, acquires and promotes the development of mineral and royalty interests and other related investments.

In addition to the reportable segments discussed above, we also operate other businesses that are not currently reported as separate segments. These businesses complement our existing operations and support our long-term growth strategic objectives. Mitigation Resources of North America® (Mitigation Resources) provides natural resource restoration and reclamation services that include stream and wetland mitigation solutions. ReGen Resources is pursuing opportunities to develop new power generation resources.

We also have items not directly attributable to an operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, the financial results of developing businesses and Bellaire Corporation (Bellaire). Bellaire manages long-term liabilities related to former Eastern U.S. underground mining activities.

During 2025, we changed the names of our reportable segments to make it easier for our stakeholders to understand the business activities within each segment. The Utility Coal Mining, Contract Mining and Minerals and Royalties segments were formerly the Coal Mining, North American Mining and Minerals Management segments, respectively. There were no changes to the composition of each segment and therefore no changes to historical segment reporting.

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 is a growing diversified natural resource company, strategically positioned to deliver stable financial returns over the long term. Our businesses operate exclusively in the U.S. and provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and products. Increasing demand for electricity, on-shoring and current federal policies are creating favorable macroeconomic trends within these industries. We continue to capitalize on these tailwinds, pursuing longer-term growth opportunities. Through our proven operational expertise, disciplined capital allocation, and an entrepreneurial yet patient approach to growth, we have methodically built unique capabilities and clear competitive advantages that enable us to capture a wide range of attractive growth opportunities. Our platform is supported by multiple vectors for value creation, and we are steadfastly committed to delivering compounding returns and expanding investor value over the long term.

Our business model is purposely built for durability and resilience. Our foundation rests on a stable base of long-term coal-mining contracts which, when combined with income generated by our mineral and royalty assets, provide dependable recurring cash flows. As new long-term contracts and investments are added each year in our other businesses, these multi-year agreements create a “layering” effect as their contributions compound. Each year’s new contracts and investments add to those of prior years, delivering increasingly predictable cash flows and annuity-like returns.

Our competitive advantages include decades of operational expertise in complex mining operations, long-standing customer relationships with industry leaders, exclusive dealership rights for MTECK draglines in 48 U.S. states and a proven ability to structure long term contracts that align incentives and deliver value to both NACCO and our customers. We also maintain a conservative capital structure that provides flexibility to pursue opportunities while maintaining financial stability.

Our Utility Coal Mining segment, anchored by our long-term mining contracts and fee-based models that provide predictable cash flows and eliminate exposure to commodity prices, provides a solid foundation of our business. We believe the increasing demand for 24/7 electricity, driven by data centers, on-shoring of manufacturing and general economic growth, combined with the current political environment, is fundamentally changing the sentiment surrounding fossil fuel-based power generation and

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provides stability the Utility Coal Mining business. These developments are improving industry-related regulations and reinforcing coal's role as an essential part of the reliable, baseload energy mix in the United States for the foreseeable future. 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 Utility 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 Utility Coal Mining segment's customers.

The Contract Mining segment represents our mining growth platform. We have long-term relationships and contracts with several of the top ten U.S. aggregates producers. Our expanding pipeline of potential mining contracts and continued engagement with customers position this segment as a key pillar for future growth. Through ongoing geographic and mineral expansion, we are building a growing portfolio of long-term contracts. New contracts and contract extensions are central to the business' organic growth strategy, with each new contract expected to contribute operating profit and EBITDA through multi-year terms that can span a decade or more. The goal is to continue Contract Mining's ongoing expansion as a leading provider of contract mining services for a variety of customers. The segment’s strong momentum is evident through recent contract wins, including a multi-year dragline services contract for a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida, which showcases our ability to expand into large scale infrastructure projects while highlighting the competitive advantage of our new electric drive MTECK draglines.

The Minerals and Royalties segment is another solid foundation of our business. It has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests with recurring cash flows. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the sale of oil, natural gas and associated natural gas liquids. The current portfolio of well-positioned assets is expected to continue to deliver solid financial results. We seek to diversify our investment and operational risk through participation in oil and gas wells with multiple operators across multiple basins. Catapult's portfolio of oil and gas mineral and royalty interests provides steady, recurring cash flows, with strategic positions in premier basins, primarily in the Permian Basin, the Haynesville Shale basin and the Appalachian basin. We also maintain equity investments in a private company that holds operated and non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.

Mitigation Resources provides natural resource restoration and reclamation services that include stream and wetland mitigation solutions. Mitigation Resources is successfully leveraging its strong reputation and clear competitive strengths to expand into additional mitigation, restoration and reclamation markets. Mitigation Resources is expected to deliver increasing profitability over time from the sale of mitigation credits and as reclamation and restoration services expand. We expect the reclamation and restoration business to generate increasing profits as this part of the business grows. The timing of profits from the mitigation solutions part of the business is inherently more variable as project credits only become available for sale once certain permit criteria are met. During 2025, Mitigation Resources operated in Alabama, Florida, Georgia, Kentucky, Mississippi, Pennsylvania, Tennessee, Texas and Virginia.

NACCO established ReGen Resources to address the rapidly increasing demand for power generation in the United States. Current projects in development include solar arrays, solar-gas hybrid projects, thermal generation and carbon capture primarily on reclaimed mining properties in Louisiana, Mississippi, Ohio, Pennsylvania and Texas. ReGen develops energy infrastructure projects directly as well as through joint ventures. Our investments in solar projects are dependent, in part, on federal tax incentives to preserve economic value. We believe all current solar projects have been safe harbored in order to preserve tax credit eligibility.

We believe our businesses have competitive advantages that provide value to customers, and the continuing investment in our businesses can create long-term value for stockholders. We have strategically leveraged our core mining and natural resource management skills to build a robust portfolio of affiliated businesses, and opportunities for additional growth remain strong. New contracts, acquisitions of additional mineral interests, improvements in industry-related regulations, and the development of other business opportunities should be accretive to our longer-term outlook.

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 at attractive returns to strengthen and grow our businesses. We also continue to maintain the highest levels of customer service and operational excellence.

Business Developments

During 2025, the Contract Mining segment executed a multi-year dragline services contract for a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida. This project should be accretive to earnings beginning in the second quarter of 2026.

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During 2025 and 2024, the Contract Mining segment amended and extended existing limestone contracts with multiple customers and expanded the scope of work with several other customers. See Item 2. Properties on page 38 in this Form 10-K for a list of the Contract Mining segment's locations and customers.

During 2025, the Minerals and Royalties segment completed $4.6 million in acquisitions of mineral interests, primarily within the Midland Basin. The acquisition includes a mix of producing wells, as well as additional upside opportunities through future development with existing operators in the area.

During 2025, we terminated NACCO's Combined Defined Benefit Plan (Combined Plan) and settled all future obligations by transferring the remaining benefit obligations to a third-party insurance company. Although the plan was over funded, we recognized a $7.8 million non-cash Pension settlement charge. See Note 1 and Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.

Operations

Utility Coal Mining Segment

The Utility Coal Mining segment operates surface coal mines under exclusive, long-term contracts to supply 100% of the fuel requirements for adjacent power plants and a synfuels plant. Each mine is fully integrated with the operation of these facilities.

As of December 31, 2025, the Utility 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). Coteau, Falkirk and Coyote Creek are in North Dakota and MLMC is in Mississippi. Each of these mines produce lignite coal. While MLMC’s coal supply contract contains a take or pay provision, 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 and includes adjustments for coal quality and certain reimbursable costs. Profitability at MLMC is affected by customer demand for coal, changes in the contractually determined sales price and actual costs incurred. 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. Current mine area reserves are sufficient to meet contractual requirements through the 2032 contract term. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. As a significant portion of MLMC’s costs are fixed, reduction in dispatch and/or reduced mechanical availability of the Red Hills Power Plant can materially reduce operating results at MLMC. Conversely, periods of higher dispatch can improve results. The Red Hills Power Plant operated below full capacity and experienced periods of reduced mechanical availability during 2024 and 2025. These factors increased per ton operating costs which adversely affected operating results in both 2024 and 2025.

In December 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant. 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 that partially offset losses as a result of the boiler outage. In February 2026, MLMC received notice from its customer that the Red Hills Power Plant experienced an unplanned outage, which is expected to lead to reduced demand and an anticipated operating loss for MLMC during 2026.

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,

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2026. As of October 1, 2026, SWEPCO is obligated 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 predictable 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 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. 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) provision 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 25 in this Form 10-K for discussion of the Utility Coal Mining segment's mineral resources and mineral reserves.

Contract Mining Segment

The Contract Mining segment provides value-added contract mining and other services for producers of industrial minerals and products. The segment is a platform for our growth and diversification of mining activities outside of the thermal coal industry. Contract Mining 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, 2025, the Contract Mining segment operates at quarries in Florida, Arkansas and Nebraska and is expected to begin operations at a quarry in Arizona during the first half of 2026. Beginning in 2026, the Contract Mining segment will also provide dragline services as part of a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida.

In addition, Contract Mining's subsidiary, Sawtooth Mining (Sawtooth), is 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. The U.S. Department of Energy holds warrants to purchase five percent non-voting, non-transferable equity in this joint venture. Thacker Pass is targeting initial lithium production in late 2027. The contract requires reimbursement for costs of mining, capital expenditures and mine closure. Sawtooth 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.

See Item 2. Properties on page 38 in this Form 10-K for a list of the Contract Mining segment's locations and customers.

Minerals and Royalties Segment

The Minerals and Royalties 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.

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The Minerals and Royalties 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. 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.

During 2025 and 2024, the Minerals and Royalties segment invested $15.0 million and $16.6 million, respectively, in Eiger Resources, which holds operated and non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. Eiger Resources 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 investment is accounted for under the equity method. Our investment is reported on the line Equity method investment in Eiger Resources in the Consolidated Balance Sheets. Due to the timing and availability of financial information, earnings or losses from this investment are recorded on a one quarter lag. See Note 1 to the Consolidated Financial Statements in this Form 10-K for further information on Eiger Resources.

Excluding the Eiger Resources investment described above, total consideration for the acquisitions of mineral and royalty interests was $4.6 million and $0.7 million, in 2025 and 2024, respectively. The 2025 acquisitions included 10.5 thousand gross acres and 0.4 thousand net royalty acres. The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres.

The Minerals and Royalties segment also manages 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 208.0 thousand gross acres and 64.4 thousand net royalty acres at December 31, 2025. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

See Item 2. Properties on page 40 in this Form 10-K for discussion of the Mineral and Royalties segment's proved reserves.

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Customers

The principal customers of the Utility Coal Mining segment are electric utilities and an independent power provider.

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

The Minerals and Royalties 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 both 2025 and 2024, three customers accounted for 10% or more 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 Revenues

Utility Coal Mining customer 31 % 29 %

Contract Mining customer 25 % 24 %

Contract Mining customer 10 % 11 %

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.

Based on industry information, we believe we were one of the ten largest coal producers in the U.S. in 2025 and 2024.

Based on industry information, we believe that we were the largest dragline operator in the U.S. in 2025 and 2024.

Competition

Coteau, Coyote Creek, Falkirk and MLMC each have only one customer. 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 Utility 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.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power, and, to a lesser extent, wind and solar. Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Fluctuations in natural gas prices and the availability of renewable energy sources can contribute to changes in power plant dispatch and customer demand for coal. Among the factors that affect competition are the price and availability of oil and natural gas, our customers' dispatch decisions, the time and expenditures required to develop energy sources, the cost of transportation, the cost of compliance with governmental regulations and the impact of federal and state energy policies. The ability of the Utility 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.

The Contract Mining segment 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 and Royalties 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 and Royalties 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 and Royalties 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

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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 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.

At Mitigation Resources, there are significant barriers to entry and the market is highly regulated; however, the markets we serve are highly fragmented and we compete with a number of regional companies. Some of these companies may have greater financial and other resources, while others may be smaller and more specialized and may concentrate their resources on specific areas of expertise. Our results are also affected by the number of competitors in a market, the demand for services in a particular market, the pricing practices of competitors and the entry of new competitors in a market.

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

In the Minerals and Royalties 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. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations. Due to these seasonal fluctuations, the Minerals and Royalties segment's results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Human Capital

As of December 31, 2025, we had approximately 1,700 employees, including approximately 1,100 employees at our unconsolidated mining operations. None of our employees 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. We automatically enroll new employees in our 401(k) plan at a 5% deferral rate, and in 2024, we implemented a program to re-enroll current employees who were not deferring at least 5%. 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, certain of which receive company contributions;

•Paid vacation and holidays;

•Parental leave;

•Short-term and long-term disability benefits;

•Wellness incentives and programs for employees;

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•Life and AD&D insurance benefits;

•Identity protection benefits;

•Charitable donation matches; and

•Employee assistance program.

Employee Development: We know that our people are our greatest asset and 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 we provide 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. Internships are also available across our family of companies. 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 provide on-going safety training, education and communication. Safety performance is monitored through physical observations from both internal and external parties and through the reporting of key metrics. Our mining operations are regulated by the U.S. Mine Safety and Health Administration and non-mining operations are regulated by the U.S. Occupational Safety and Health Administration.

During 2025, an incident at a quarry in Florida resulted in two employee fatalities. The event is currently under investigation by the U.S. Mine Safety and Health Administration. In the aftermath of this incident, we are reviewing ways to further strengthen our safety guidelines and reinforce our safety expectations across the organization. Our employees are the nucleus of NACCO’s success, and their safety will always come before all else. We maintain insurance with respect to operating the dragline involved in this incident and related liabilities (which are subject to deductibles) and believe that our insurance coverage will be adequate to cover any liabilities.

Our operations have 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. As part of our efforts to continuously improve our safety programs, NACCO’s safety professionals from across the organization meet regularly to share ideas and best practices. We believe communication related to safety incidents, near misses and protocols is essential to continuously developing and maintaining robust safety practices. This communication also enables the 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 to comply 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. The Company believes the code and these policies represent sound practices and provide a strong framework for the conduct of our Board and employees. 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.

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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.

Government Regulation and Environmental Matters

Operations on our properties, projects and mineral interests must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, permits and other licensing requirements, reclamation and restoration of properties, management of materials, air quality, water quality, limitations on land use as well as the protection of wetlands, plant and wildlife. These laws and regulations, which are extensive and subject to change, could have a significant effect on our production costs and our competitive position. While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs could be significant.

Future legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may result in substantial increases in equipment and operating costs and delays, interruptions, or a termination of operations, the likelihood or extent of which we cannot predict. We intend to continue to comply with regulatory requirements as they evolve by timely implementing necessary modifications and/or operating procedures.

The following is a summary of the more significant existing government regulations and environmental matters to which we or our customers'/lessees' business operations are subject and for which compliance may have a material adverse effect on our business, results of operations and financial condition. For additional information regarding our material risks, please refer to Item 1A - Risk Factors on page 15.

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 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 operations. 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 our business.

Surface Mining Control and Reclamation Act (SMCRA)

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. SMCRA stipulates compliance with many other major environmental programs. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

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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, 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.

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 businesses 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 by the customers throughout the production stage.

Clean Air Act (CAA) and Air Emissions

The process of burning coal and drilling for oil and natural gas can cause many compounds and impurities to be released into the air, including sulfur dioxide, nitrogen oxides, methane, mercury, particulates and other matter. Federal and state laws that extensively regulate the emissions of materials into the air affect our operations both directly and indirectly. Direct impacts on operations can occur through permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on operations can occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, methane, mercury, particulate matter and other compounds.

Greenhouse Gas (GHG) Emissions and the Mercury and Air Toxics Standards (MATS)

In May 2024, the Environmental Protection Agency (EPA) published the final rules for GHG emissions and MATS in the Federal Register. 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.

In 2023, the EPA issued its methane rules that establish new source and first-time existing source standards of performance for GHG and volatile organic compound emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. The EPA also finalized a Waste Emissions Charge implementation rule in November 2024; however, the Congressional Review Act was used to disapprove EPA’s implementation rule in March 2025. As a result, no methane emission fees are being assessed or collected. In November 2025, the EPA announced a final rule to extend several compliance deadlines for the oil and gas industry.

The EPA under the Trump Administration has made efforts to repeal or otherwise modify GHG and MATS regulations at the federal level. On June 11, 2025, EPA announced a plan to repeal the GHG rule but has not yet published a final repeal of the rule. On February 12, 2026, the EPA revoked the 2009 Endangerment Finding, which found that six GHGs endanger public health, thus removing the EPA’s authority to regulate GHGs. Additionally, on February 23, 2026, the EPA repealed the MATS rule. If not repealed, the 2024 GHG rule will require compliance at our customers' facilities as early as 2029 and 2032. We cannot predict whether such efforts will ultimately be successful or what effects they may have on our business or results of operations and on the business and results of operations of our customers/lessees.

At the same time, many states, regions, and governmental bodies have adopted or are considering policies that regulate greenhouse gas emissions, including imposing fees or taxes on emissions from certain facilities such as coal‐fired power plants through cap‐and‐trade programs, carbon taxes, or climate “superfund” laws. Other states are advancing plans to expand renewable energy use, which may further reduce the role of coal and other fossil fuels. Depending on future federal or state regulatory actions and the outcomes of potential legal challenges, demand for coal, oil, and natural gas could decline, adversely affecting our operations.

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National Ambient Air Quality Standards (NAAQS)

The CAA requires the EPA to set NAAQS for certain air pollutants. The EPA has set NAAQS for ozone, particulate matter, sulfur dioxide, nitrogen oxides, carbon monoxide and lead. Over the years, the EPA has made the NAAQS more stringent. Each state must develop a plan to be approved by the EPA for achieving and maintaining NAAQS within its borders. These plans impose limits on emissions from pollution sources, including fossil fuel-fired plants. Areas meeting NAAQS are designated as attainment areas. Areas not meeting NAAQS are designated as non-attainment areas, and more stringent requirements apply in those areas, including stricter controls on industrial facilities and more complicated and public permitting processes.

During 2024, the EPA finalized more stringent NAAQS for particulate matter that may increase the likelihood of certain areas being designated as non-attainment areas. The more stringent NAAQS are currently subject to a legal challenge seeking to overturn the standards, but the challenge is currently being held in abeyance. On March 12, 2025, the EPA announced that it would be reconsidering the NAAQS for particulate matter and that it would release guidance to increase flexibility on NAAQS implementation and direction on permitting obligations. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the EPA finalized the 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.

In 2023, the EPA published the Good Neighbor Plan, which decreases, over time, the ozone-season NOx allowances for EGUs in the affected states by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. In 2024, the U.S. Supreme Court (SCOTUS) decided to stay the Good Neighbor Plan pending further review. In March 2025, the EPA announced a rollback of the Good Neighbor Plan, leaving in place pre-Good Neighbor Plan requirements from CSAPR. Additional emission restrictions under the CSAPR or the Good Neighbor plan would increase the cost of operating the customer facility serviced by MLMC.

Regional Haze

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 2024, the EPA issued a proposed partial denial of the North Dakota state implementation plan. In May 2025, the EPA granted an administrative petition for the EPA to reconsider a portion of the Clean Air Act’s regional haze rule which disapproved North Dakota's state implementation plan. On a broader scale, in March 2025, the EPA announced it was reconsidering its implementation of the Regional Haze Program and intends to review and revise the regulations to streamline the program and change compliance expectations. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

Clean Water Act (CWA)

The CWA affects certain of our 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 (USACE) for operations in waters of the United States (WOTUS.) In 2023, the SCOTUS issued a decision in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. The decision provides a clear standard that substantially restricts the USACE and the EPA’s ability to regulate certain types of wetlands and streams. Specifically, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional. As a result of the Sackett decision, the EPA and the USACE revised the definition of WOTUS and promulgated a final rule. The new rule did 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 November 2025, the EPA and the USACE proposed a new definition of WOTUS that contemplates a substantially narrower jurisdiction. We are currently unable to predict any specific changes or how such changes, if any, may impact our 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

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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.

Resource Conservation and Recovery Act (RCRA)

The 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) and CCR Management Units (CCRMUs). In May 2024, the EPA published a final rule amending CCR regulations which introduced 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. During 2025, the EPA announced a number of interpretation and guidance changes to its CCR Rule, including its intention to reconsider the CCR Rule, which will require a new round of notice-and-comment rulemaking. No schedule for this rulemaking has yet been announced. We are currently unable to predict any specific changes or how such changes, if any, may impact our 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 2023, the EPA proposed to deny the owner’s application. The owner and other parties submitted additional information and comments supporting the owner’s position. The owner and the EPA continue to work through a path forward to provide a long-term solution. Additionally, the owner is taking operational steps to ensure there is no interruption to its disposal needs and no interruption of operations while working through the issue.

National Environmental Policy Act (NEPA)

The 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. Historically, this process may take several years to complete. In May 2025, the SCOTUS significantly narrowed the scope of environmental review required under NEPA, reinforcing that courts must give substantial deference to federal agencies. The SCOTUS iterated that NEPA is a procedural statute, not outcome-mandating. Furthermore, agencies are not required to analyze effects from separate, future or geographically distinct projects. Finally, agencies are permitted to limit NEPA analysis to impacts directly tied to the project and within their jurisdiction. The Council on Environmental Quality (CEQ) emphasized the need for agencies to streamline procedures and ensure that the NEPA process does not go on for too long in time or in volume. In January 2026, the CEQ published a final rule formally rescinding all NEPA implementation regulations and providing that CEQ will no longer issue government-wide NEPA regulations. This action moves all NEPA implementation to each individual federal agency and each individual federal agency must now revise its own NEPA procedures within one year, per CEQ direction. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

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.

Endangered Species Act (ESA)

The ESA and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Some of our properties, projects 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 own property, projects or mineral interests. The ESA restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (MBTA). Compliance with ESA and MBTA requirements can significantly delay, limit, or even prevent the development of our properties, projects and mineral interests, and also result in increased costs.

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Drilling and Production

Our 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 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.

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 USACE and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the USACE does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Regulation of Hydraulic Fracturing

The operators that produce oil and gas sometimes engage in hydraulic fracturing to stimulate production of hydrocarbons 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 process is typically regulated by state oil and natural gas commissions.

Several states where we own interests in oil and gas producing properties, including Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances with regard to the use of fracturing fluids or require the disclosure of the composition of hydraulic-fracturing fluids. For example, the Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. 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. These existing or any new legal requirements regulating or prohibiting the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, will likely result in added costs to comply and affect the operators’ rate of production.

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. For example, Oklahoma, New Mexico and Texas have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. 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.

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There has been increasing public controversy regarding hydraulic fracturing with regard to water, including the use of a significant amount of water, impacts on drinking water and the potential for impacts to surface water and groundwater. 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, a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. 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.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states where we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where operators that produce our oil and gas conduct operations, those operators may incur substantial costs to comply with these requirements, experience delays, or curtailment, in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

Natural Gas and Oil Sales and Transportation

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, or what proposals, if any, might be enacted by Congress or the various state legislatures.

Other Laws and Regulations

On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was signed into law. The OBBBA includes changes to U.S. tax law including provisions for bonus depreciation, current expensing of research expenditures and changes to the interest deductibility threshold. The changes resulting from the tax provisions in OBBBA are not expected to have a material impact on our results of operations.

The OBBBA includes substantial changes to U.S. solar energy tax policy which could have a material impact on the

projects being developed by ReGen Resources. Current projects in development include solar arrays, solar-gas hybrid projects, thermal generation and carbon capture primarily on reclaimed mining properties in Louisiana, Mississippi, Ohio, Pennsylvania and Texas. ReGen develops energy infrastructure projects directly as well as through joint ventures. Our investments in solar projects are dependent, in part, on federal tax incentives to preserve economic value. We believe all current solar projects have been safe harbored in order to preserve tax credit eligibility. We have approximately $8.4 million of capitalized assets associated with our solar projects. We have incurred, and will continue to incur, costs in connection with these projects and the results of operations and/or return on investment could be lower than anticipated.

The United States has enacted and proposed to enact significant new tariffs. Additionally, President Trump has directed

various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion and

commentary regarding potential significant changes to U.S. trade policies, treaties, and tariffs. While in February 2026 the SCOTUS limited the ability of the President of the United States to implement certain tariffs without the express authorization of Congress, there continues to exist significant uncertainty about the future relationship between the U.S. and other countries with respect to such trade policies, treaties, and tariffs.These developments, or the perception that any such policies, treaties, or tariffs could be implemented, could restrict our access to suppliers and increase the cost of equipment and supplies imported into the U.S.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following tables set forth as of March 1, 2026 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

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name Age Current Position

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. See Item 1. Business — Government Regulation and Environmental Matters on page 9 in this Form 10-K for discussion of regulations that could materially adversely affect our businesses.

Risks related to the Utility Coal Mining segment

MLMC is subject to risks associated with our capital investment, operating and equipment costs, changes in customer demand and inflationary adjustments.

Profitability at MLMC is affected by customer demand for coal, changes in the contractually determined sales price and actual costs incurred. The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation. As such, increased costs or decreased revenues could materially reduce our profitability. As a significant portion of MLMC’s costs are fixed, reduction in dispatch and/or reduced mechanical availability of the Red Hills Power Plant can and historically has materially reduced operating results at MLMC. Conversely, periods of higher dispatch can improve results. In February 2026, MLMC received notice from its customer that the Red Hills Power Plant experienced an unplanned outage, which is expected to lead to reduced demand and an anticipated operating loss for MLMC during 2026.

Any reduction in customer demand at MLMC, including fluctuations in demand due to planned and unplanned outages at the customer's Red Hills Power Plant, unanticipated weather conditions, economic conditions, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

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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 Utility Coal Mining segment's profits are derived from long-term mining contracts. Although we have long-term contracts, 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 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 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.

The potential impact 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.

In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict 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.

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 Utility 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 Utility 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.

The Utility 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 Utility 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.

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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; and environmental and other governmental regulations. Changes in the utility industry that affect NACCO's customers could also adversely affect us. 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.

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

Maintaining power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Utility Coal Mining segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. The Red Hills Power Plant operated at below full baseload capacity and experienced periods of reduced mechanical availability during 2024 and 2025. A decrease in coal consumption could have a material adverse effect on the Utility 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 25 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.

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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.

Risks related to the Contract Mining segment

We have experienced growth in our Contract Mining business in recent periods and we may not be able to sustain growth or manage future growth effectively.

We have expanded our overall Contract Mining business, operations and headcount in recent periods. The Contract Mining segment's operating expenses may increase as we continue to scale the Contract Mining business. We must effectively integrate, develop and motivate employees, while integrating new equipment and customers in an efficient and effective manner. We anticipate that we 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 Contract Mining business, operating results and financial condition.

Our Contract Mining business faces competition from customers that choose to self-perform mining operations and from other mining companies.

We face competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services we provide. We cannot be certain that our existing customers will continue to outsource these services to us in the future, which could adversely affect the Contract Mining 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 Contract Mining'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.

Contract Mining 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, 2025, over 80% of the Contract Mining segment's quarries 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 our services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the Contract Mining business.

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Risks related to the Minerals and Royalties 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 and Royalties 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, 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 and/or increased costs may reduce the amount of oil and natural gas that third-party operators can produce economically. 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 certain rights; and if possible, 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 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 and Royalties 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. 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 and Royalties 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 and Royalties segment’s financial condition or results of operations.

The Minerals and Royalties 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; 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; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals and Royalties 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 and Royalties segment’s financial condition or results of operations.

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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 and Royalties 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 other energy-related 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 control. General concerns about the fundamental soundness of the economy may cause customers to defer projects, even if they have available financing. Prolonged uncertainties in the capital markets, or the returns of constrained capital market conditions, could have adverse effects on our customers. All of the aforementioned risks could reduce the viability of project development, which would adversely affect our financial condition and results of operations.

The OBBBA includes substantial changes to U.S. solar energy tax policy which could have a material impact on the

Operating results may vary significantly from period to period and are inherently unpredictable.

Demand for our mitigation credits and mitigation services has been, and will likely continue to be, cyclical in nature and vulnerable to downturns in the general economy, as well as downturns in government infrastructure spending. We base our planned operating expenses in part on our expectations of future revenue, and a significant portion of our expenses are fixed in the short-term. 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 will not be even quarter over quarter, and this 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) military conflicts, inclusive of acts of terrorism; (v) supply chain disruptions, inclusive of tariff effects; (vi) announcements concerning NACCO, our customers or competitors; (vii) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (viii) the general state

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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.

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, 2025, 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, 2025, accounted for our remaining voting power. As of December 31, 2025, certain members of our extended founding family held approximately 35 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 81 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.

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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.

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. 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 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. Any such factors, 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.

We hold a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. 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.

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 alleged 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. The rapid evolution and increased availability of artificial intelligence (AI) may intensify cybersecurity risks by making cyber-attacks more sophisticated and cybersecurity incidents more difficult to detect, contain and mitigate. As threat actors adopt and deploy AI tools, the speed and sophistication of cyber threats and privacy risks may increase across our environment and those of our customers and vendors.

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. This process includes reviewing the state of our cybersecurity program, discussing emerging cybersecurity developments, including AI, and monitoring the steps that management has taken to mitigate such exposure. In 2025, 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. We recognize the constantly evolving nature of cyber threats and are committed to cultivating a strong security culture, maintaining vigilance and continuously enhancing our cybersecurity systems and controls. For additional information regarding our cybersecurity risks, please refer to Item 1A - Risk Factors on page 15.

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Item 2. PROPERTIES

Utility 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 15.

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 2025 Subject to SEC Section 1300 Reporting.

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Figure 1.1 Surface Coal Mines Operational During 2025 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)

The Falkirk Mining Company 6.6 7.5 7.3

Coyote Creek Mining Company 2.2 1.9 1.8

Mississippi Lignite Mining Company 2.7 1.9 2.7

Table 1.1 Production Summary

2.0MINING PROPERTIES SUBJECT TO SUBPART 1300 OF REGULATION S-K REPORTING

2.1Red 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)

Mississippi Lignite Mining Company 2.7 1.9 2.7

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.

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 8,337 acres of surface interest and 5,436 acres of coal interests. MLMC holds leases granting the right to mine approximately 4,660 acres of coal interests and the right to utilize approximately 4,384 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,860 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.

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

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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, 2025 is $54.4 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

Mineral Resources and Reserves have been summarized from the December 31, 2024 TRS for MLMC and have been modified from mining depletion. The Mineral Resources and Mineral Reserves as of December 31, 2025 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.

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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, 2025 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)

Note:

–Mineral Resources estimates have been prepared by a qualified person (QP) employed by NACCO Natural Resources.

–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.

Table 2.2 Mineral Resources Summary as of December 31, 2025

The Mineral Reserves as of December 31, 2025 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.

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Lignite Coal Reserve Classification Tonnage(Kt) Grades/Qualities

Calorific Value (Btu/lb) Moisture (%wt) Ash (%wt) Sulfur (%wt)

Note:

–Mineral Reserves Estimates have been prepared by a QP employed by MLMC.

–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, 2025

Table 2.4 describes the difference between the Mineral Reserves and Mineral Resources reported as of December 31, 2024 and December 31, 2025.

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, 2025 reflect modifications from mining extraction of Mineral Reserves. No updates to Mineral Resources were made for 2025. Additionally, MLMC delivered 2.7 million tons during 2025.

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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.

NC US Equity

NC · 10-K · period ended 2025-12-31

Item 1. BUSINESS

Item 1A. RISK FACTORS

Item 1B. UNRESOLVED STAFF COMMENTS

Item 1C. CYBERSECURITY

Item 2. PROPERTIES

NC US Equity☆

NC · 10-K · period ended 2025-12-31

Item 1. BUSINESS

Item 1A. RISK FACTORS

Item 1B. UNRESOLVED STAFF COMMENTS

Item 1C. CYBERSECURITY

Item 2. PROPERTIES

NC US Equity