NACCO INDUSTRIES INC (NC) Business

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 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. See Note 1 to the Consolidated Financial Statements in this Form 10-K for further information on Eiger Resources.

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:

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

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES