What changed in this filing

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Item 1. Business

2026-03-04 compared with 2025-03-05 · 360 added, 460 removed, 211 unchanged (80% of the section changed)

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® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation ® (NACCO Natural Resources, and with NACCO collectively, the Company, we, our or us), bring natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses.

We operate under three business segments:

Coal Mining, North American Mining ® (NAMining) and Minerals Management.

The Coal Mining segment operates surface coal mines for power generation companies.

The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals.

The Minerals Management segment, which includes the Catapult Mineral Partners (Catapult) business, acquires and promotes the development of mineral interests.

Mitigation Resources of North America ® (Mitigation Resources) provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services.

In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.

We have items not directly attributable to a reportable segment that are not included in the reported financial results of the operating segment.

These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, and the financial results of Bellaire Corporation (Bellaire), Mitigation Resources, ReGen Resources and other developing businesses.

Bellaire manages our long-term liabilities related to former Eastern U.S.

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’s portfolio of businesses operate under the umbrella of NACCO Natural Resources.

Management continues to view our long-term business outlook positively.

Our businesses provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and chemicals.

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.

Management is confident in our trajectory and business prospects as well as longer-term growth opportunities.

While we realize the coal mining industry continues to face challenges, we believe the current political environment may change the sentiment surrounding fossil fuel industry-related regulations.

These developments are expected to further support coal as an essential part of the energy mix in the United States for the foreseeable future.

NAMining is our primary platform for growth around mining activities.

With a focus on operational excellence, scalability and driving profitable growth, NAMining expects to improve operating margins as well as achieve additional growth through its ongoing business development activities.

New contracts and contract extensions are central to the business' organic growth strategy.

The goal is to continue NAMining's ongoing expansion as a leading provider of contract mining services for customers who produce a wide variety of minerals and materials, and we expect NAMining to be a substantial contributor to operating profit over time.

The Minerals Management segment, through our Catapult business, has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests in the United States that is expected to deliver near-term cash flow yields and long-term growth.

As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids, typically net of post-production expenses and taxes.

We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life.

The current portfolio provides a strong foundation of well-positioned assets that are expected to continue to deliver solid financial results.

This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the full cost of exploration, production and/or development.

We intend to continue these activities, while at the same time evaluating investments in non-operated working interests that we believe can reliably increase cash flow and enhance overall returns.

As a non-operator, we seek to diversify our investment and operational risk through participation in oil and gas wells with multiple operators across multiple basins.

While the timing of returns could vary, we maintain a long-term perspective and believes the Minerals Management segment will provide unlevered after-tax returns on invested capital in the mid-teens as the business matures.

Mitigation Resources, which provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services, continues to build on the substantial foundation it has established over the past several years.

Our Mitigation Resources business offers an opportunity for growth and diversification in an industry where we have a strong

reputation as well as substantial knowledge and expertise.

In addition, Mitigation Resources is providing ecological restoration services for abandoned surface mines and was named a designated provider of abandoned mine land restoration by the State of Texas.

Mitigation Resources is working to develop a protected habitat for toads in Texas, as well as pursuing additional environmental restoration projects.

We believe that Mitigation Resources can provide solid rates of return on capital employed as this business matures.

As of December 31, 2024, we have 11 mitigation banks and other mitigation projects located in Alabama, Florida, Georgia, Mississippi, Pennsylvania, Tennessee and Texas.

We believe our businesses have competitive advantages that provide value to customers and continuing to invest in our businesses can create long-term value for stockholders.

We have strategically leveraged our core mining and natural resources management skills to build a robust portfolio of affiliated businesses and opportunities for additional growth remain strong.

Acquisitions of additional mineral interests and improvements in the outlook for Coal Mining segment customers, as well as new contracts at Mitigation Resources and NAMining and development of other business opportunities should be accretive to our longer-term outlook.

NACCO also continues to pursue activities which can strengthen the resiliency of our existing coal mining operations.

We 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

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 Coal Mining segment, as fuel cost is a significant driver for power plant dispatch.

Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers.

Fluctuating natural gas prices, weather and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants.

We continue to look for ways to create additional value by utilizing our core mining competencies, which include reclamation and permitting.

NACCO established ReGen Resources to utilize these skills to address the rapidly increasing demand for additional power generation sources in the United States through development of energy-related projects that utilize multiple generation technologies, such as solar combined with gas-fired generation, primarily on reclaimed mining properties.

These projects could be developed by ReGen Resources directly or through joint ventures that include partners with expertise in energy development projects and their financing.

Current opportunities in development include solar arrays, solar-gas hybrid projects and carbon capture on reclaimed mine land in Mississippi and Texas, as well as early-stage review of projects in other states.

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 to strengthen and expand our businesses.

We also continue to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.

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

Coal Mining Segment

During 2023, Mississippi Lignite Mining Company (MLMC) received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023.

We assessed MLMC's long-lived assets for impairment and recorded a $65.9 million impairment charge in 2023.

See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge.

While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations.

We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.

The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas.

All production from Sabine was delivered to

Southwestern Electric Power Company's (SWEPCO) Henry W.

Pirkey Plant (the Pirkey Plant).

SWEPCO is an American

Electric Power (AEP) company.

As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023.

Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services.

Sabine will provide mine reclamation services through September 30, 2026.

As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.

NAMining Segment

Sawtooth Mining, LLC (Sawtooth) will be the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada.

Thacker Pass is owned by a joint venture between Lithium Americas Corp.

LAC) and General Motors Holdings LLC.

Thacker Pass commenced construction in 2023 and is targeting initial production in 2027.

Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating.

In addition to providing comprehensive mining services,

Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.

During 2024 and 2023, NAMining amended and extended existing limestone contracts with two customers and expanded the scope of work with several other customers.

New contracts signed in 2024 are expected to be accretive to earnings starting in 2026.

Minerals Management Segment

During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of

2024, in Eiger, LLC (Eiger), which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.

During 2023, Minerals Management acquired $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin.

In December 2023, we entered into a power purchase agreement with the Tennessee Valley Authority (TVA) for the energy generated from a proposed 67.5 MW solar photovoltaic electric generation facility to be developed on reclaimed land at our Red Hills Mine.

The development of this project is subject to the favorable completion of an Environmental Assessment under the National Environmental Policy Act (NEPA) and approval of an interconnection agreement with TVA.

In addition, we entered into an engineering, procurement and construction agreement related to the interconnection of the project during 2025.

The estimated commercial operation date for this generation facility is late 2027.

Coal Mining Segment

The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model.

Coal is surface mined in North Dakota and Mississippi.

Each mine is fully integrated with our customer's operations.

As of December 31, 2024, the Coal Mining segment's operating coal mines were:

The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and MLMC.

Each of these mines supply lignite coal for power generation and delivers our coal production to an adjacent power plant or synfuels plant under a long-term supply contract.

While MLMC’s coal supply contract contains a take or pay provision, the contract contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party;

all other coal supply contracts are requirements contracts.

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.

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.

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.

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.

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MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S.

inflation rates.

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

As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

MLMC's customer operates the Red Hills Power Plant, which supplies electricity to TVA under a long-term power purchase agreement.

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.

Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC.

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,

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.

Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S.

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

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

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.

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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;

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.

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For tax purposes, the Unconsolidated Subsidiaries are included within our consolidated U.S.

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

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.

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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.

Properties on page 29 in this Form 10-K for discussion of our mineral resources and mineral reserves.

NAMining Segment

The NAMining segment provides value-added contract mining and other services for producers of industrial minerals.

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.

NAMining provides contract mining services for independently owned mines and quarries, creating value for our customers by performing the mining aspects of our customers’ operations.

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, 2024, NAMining operates in Florida, Texas, Arkansas, Virginia and Nebraska.

In addition, Sawtooth will supply all of the lithium-bearing ore requirements for Thacker Pass, which is currently in the development stage with construction activities underway.

Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating.

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.

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.

Minerals Management Segment

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

The Minerals Management segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests (collectively mineral and royalty interests).

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.

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.

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Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage.

A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but royalty interests may be calculated net of post-production expenses, and typically have no environmental liability.

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.

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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;

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.

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For example, where we own an ORRI in a lease on the same tract of land in which we own a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development.

The Minerals Management segment will benefit from the continued development of our mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired as the capital costs or lease operating expenses are born entirely by the operators or working interest owners.

During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of

2024, in Eiger, which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.

This entity meets the definition of a VIE.

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 contract is accounted for as an equity method investment.

During 2024, we recorded $0.6 million, which represented our share of earnings, as Earnings of unconsolidated operations on the Consolidated Statements of Operations.

Our investment is reported on the line Equity method investment in Eiger, LLC in the Consolidated Balance Sheets.

Due to a lag in Eiger's financial reporting, earnings or losses from this investment will be recorded on a one quarter lag.

Excluding the Eiger investment described above, total consideration for the acquisitions of mineral and royalty interests was $0.7 million and $36.7 million, in 2024 and 2023, respectively.

The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres.

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.

We also manage legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas).

The 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.

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Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8 th royalty lease, and assumes a 1/4 th royalty rate for unleased acres.

Properties on page 29 in this Form 10-K for discussion of our proved reserves.

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

The principal customers of the NAMining segment are limestone producers and to a lesser extent, sand and gravel producers.

In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers.

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

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 2024 and 2023, three customers and two customers, respectively, accounted for more than 10% of consolidated revenue.

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:

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Segment 2025 2024

Coal Mining customer 29 % 40 %

NAMining customer 24 % 22 %

NAMining customer 11 % 7 %

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.

Coteau, Coyote Creek, Falkirk and MLMC each have only one customer for which they extract and deliver coal.

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.

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 Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors.

In addition, the customers' facilities were specifically designed to use the coal being mined.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power.

In addition, it competes with subsidized sources of energy, primarily wind and solar.

Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on pricing of renewable energy and our customers' dispatch decisions, which may also take into account carbon dioxide emissions.

The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and develop our reserves will depend upon the interaction of these factors.

Coal-fired electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share.

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.

Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal.

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

Fluctuations in natural gas prices and the availability of renewable energy sources, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal.

Over the longer term, we continue to believe that customer demand will remain pressured by regulations mandating or incentivizing the purchase of power from subsidized renewable energy sources, particularly wind and solar.

Business — Government Regulation on page 9 in this Form 10-K for further discussion.

Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

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

in 2024 based on total coal tons produced.

NACCO believes that we were the largest dragline operator in the U.S.

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

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

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

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

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

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.

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.

We have experienced limited variability in our results due to the effect of seasonality;

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Conversely, mild weather can result in weaker demand for coal-fired power generation.

The NAMining segment extracts a significant amount of the annual limestone produced in Florida.

The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions, significant weather events, and pandemics, all of which can result in variations in demand for aggregates.

In the Minerals Management segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production.

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.

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Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices during the first and fourth quarters.

Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations.

Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations.

Due to these seasonal fluctuations, Minerals Management results of operations for individual quarterly periods may not be indicative of the results that may be realize on an annual basis.

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, 2024, we had approximately 1,700 employees, including approximately 1,100 employees at our unconsolidated mining operations, none of which are represented by a collective bargaining agreement.

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.

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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.

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• Flexible spending accounts for both healthcare and dependent care;

• Health savings accounts and health reimbursement accounts, both of which receive company contributions;

• Health savings accounts and health reimbursement accounts, certain of which receive company contributions;

• Paid vacation and holidays;

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• Short-term and long-term disability benefits;

• Wellness incentives for employees;

• Wellness incentives and programs for employees;

• Life and AD&D insurance benefits;

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Employee Development:

We recognize that our culture and success is strengthened when employees are respected, motivated and engaged.

We work to match employees with assignments that capitalize on the skills, talents and potential of each employee, and provides opportunities for professional growth.

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.

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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.

Employee safety in the workplace is one of our core values.

We are committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication.

The National Mining Association ranks NACCO as an industry leader in safety, and our incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data.

We have earned more than 100 safety awards at the state and national levels since the 1980s.

NACCO strives to have zero safety incidents or injuries.

Our operations have onsite safety personnel who train employees in safe work practices, review safety-related incidents and recommend improvements when appropriate.

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.

We believe communication related to near misses, safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.

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.

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We have processes in place for compliance with our Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy.

All of our Directors and employees annually complete certifications with respect to compliance with our Code of Corporate Conduct.

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.

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We will match employee contributions up to $5,000 per employee if program criteria are met.

Please visit nacco.com/stewardship/ for the full text of certain NACCO stewardship policies.

Available Information

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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

Our operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater.

In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from our Coal Mining segment.

Numerous federal, state and local governmental permits and approvals are required for coal mining operations.

Our subsidiaries hold or will hold the necessary permits at all of our lignite coal mining operations.

At the coal mining operations where our subsidiaries hold the permits, we are required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.

Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies.

Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of Minerals Management segment.

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

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Environmental Laws

Our coal mining operations are subject to various federal environmental laws, as amended, including:

Our operations are subject to various federal environmental laws, as amended, including:

• the Surface Mining Control and Reclamation Act of 1977 (SMCRA);

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In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws.

These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations.

Both federal and state inspectors regularly visit mines to enforce compliance.

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 the Coal Mining segment.

The election of Donald Trump, paired with Republican control of Congress, is likely to have a significant and favorable impact on the regulatory environment, particularly for fossil fuels.

President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources.

It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed.

Surface Mining Control and Reclamation Act

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.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency.

These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation.

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.

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SMCRA establishes operational, reclamation and closure standards for surface coal mines.

We accrue for the costs of final mine closure, including the cost of treating mine water discharges, at mines where our subsidiaries hold the mining permit.

While these obligations are largely unfunded, they can require securitization through bonding, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA.

Army Corps of Engineers regulates activities affecting navigable waters, and the U.S.

Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting.

In addition, the U.S.

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

Army Corps of Engineers and the Office of Surface Mining Reclamation and Enforcement (OSMRE) have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.

Greenhouse Gas (GHG) Emissions

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides (NOx), mercury, particulates and other matter.

Federal and state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly.

Direct impacts on coal mining operations occur through permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter.

Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants.

In May 2024, the EPA published the final rules for GHG emissions and Mercury Air Toxics Standards (MATS) in the Federal Register.

The final MATS and GHG rules will require compliance as early as 2027 and 2032, respectively.

Previous efforts by the EPA were met with extensive litigation and there has been a similar response to the new GHG and MATS rules.

State coalitions have filed lawsuits challenging both of these rules.

Several other entities, including electric generators and industry groups, have joined the lawsuits.

In July 2024 and October 2024, stay motions for the GHG and MATS rules were denied by the U.S.

Court of Appeals for the District of Columbia Circuit (the D.C.

Circuit Court), respectively.

Following the D.C.

Circuit Court denial, emergency stay motions were filed for the GHG and MATS rules with the Supreme Court of the United States (SCOTUS).

In October 2024, the SCOTUS denied the stay applications for the GHG and MATS rules.

The GHG and MATS cases continue through the normal procedures in the D.C.

Circuit Court without stays in place.

On February 19, 2025, the D.C.

Circuit granted an EPA motion to hold the GHG case in abeyance for 60 days while the new EPA evaluates its position on the GHG rule.

Similarly, on February 20, 2025, the D.C.

Circuit granted an EPA motion to hold the MATS case in abeyance and removing the case from the upcoming oral argument calendar while the new EPA evaluates its position on the MATS rule.

We cannot predict the full impact of the MATS and GHG rules on the operations of the coal-fired generation facilities operated by our customers;

however, if the rules go into effect, the additional compliance costs could have a material adverse effect on our Coal Mining segment.

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.

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.

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The MATS rules finalize changes for the filterable particulate matter surrogate emission standard for non-mercury metal hazardous air pollutants for existing coal-fired EGUs, the filterable particulate matter emission standard compliance demonstration requirements and the mercury emission standard for lignite-fired EGUs.

Review of the MATS rules indicate that the EPA significantly reduced the fine particulate matter emission standard for all existing coal-fired EGUs and will require continuous monitoring equipment to demonstrate compliance.

Furthermore, the EPA elected to remove the lignite subcategory for mercury limits and will require lignite-fired EGUs to meet the same standard as other types of coal.

The recent change in presidential administrations, recent executive actions, and the resulting changes at the EPA make it unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed.

The various parties are working through the legal and administrative processes and the actual outcome remains unknown at this time.

The CAA requires the EPA to review national ambient air quality standards (NAAQS) every five years to determine whether revisions to current standards are appropriate.

In addition, states are required to submit to the EPA revisions to their state implementation plans (SIPs) that demonstrate the manner in which the states will attain NAAQS every time a NAAQS is issued or revised by the EPA.

The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for

When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs.

If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to affect the revision.

Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs.

Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone and nitrogen oxides.

Our coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter.

In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision.

On May 6, 2024, the EPA lowered the level for particulate matter by 25%.

States are required to update their state implementation plans by February 2027.

The rule is currently being challenged at the D.C.

Circuit by a coalition of states led by Kentucky and West Virginia.

Oral argument was held at the D.C.

Circuit on December 16, 2024.

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address interstate transport of pollutants.

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.

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.

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additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS.

The EPA began

implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective.

In 2019, certain states submitted SIPs to the EPA in response to the 2015 ozone standard reduction.

On February 13, 2023, the EPA rejected the SIPs.

The EPA’s action to deny the SIPs was challenged in various courts, including the 5th Circuit Court of Appeals (the Fifth Circuit).

The Fifth Circuit issued a stay of the SIP rejection in Texas, Louisiana, and Mississippi which prevents the federal implementation plan (FIP) from going into effect pending the outcome of the litigation challenges.

On June 5, 2023, the EPA published the FIP in the Federal Register.

The FIP decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stay beginning in 2024 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls.

On July 31, 2023, the EPA promulgated an interim rule (Interim FIP) that addresses the various judicial orders where the SIP rejection has been stayed.

The Interim FIP requires these states to return to the previously approved NOx trading program and emission caps.

The Interim FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the power plants in these states under the Group 2 trading program.

In June 2024, the SCOTUS decided to stay the rule pending further review on the merits because the EPA's justifications were flawed.

The Ozone Transport Rule was premised on its applicability to 23 states, but litigation resulted in the removal of 12 of those states that accounted for over 70 percent of the emissions the EPA had planned to address.

The EPA purported to select control measures that would maximize cost effectiveness in achieving downwind ozone air quality improvements, but it did so based on an assumption that all 23 states would apply the uniform levels of controls required by the FIP.

The case was remanded to the D.C.

Circuit where the parties fully briefed the case.

Subsequent to briefing, the EPA asked to partially remand the rule to "take a supplemental final action addressing the record deficiency preliminarily identified by the Supreme Court." The EPA finalized the supplemental response in December 2024.

On February 6, 2025, the EPA filed a motion requesting abeyance of litigation for 60 days to allow a transition to the new administration.

On February 21, 2025, the D.C.

Circuit denied the EPA's request to hold the litigation in abeyance and extending the briefing schedule through March 27, 2025.

Should the FIP be fully implemented in states where a stay has been issued, the rule could influence the closure of some coal-fired EGUs that have not installed selective catalytic reduction technologies, potentially including the EGU supplied by MLMC.

We cannot predict the outcome of the legal challenges to the:

(i) various state challenges;

(ii) the FIP promulgated on June 5, 2023;

(iii) the interim final rule promulgated on July 31, 2023;

nor (iv) the supplemental response dated December 10, 2024 that seeks to address the judicial orders.

If the original FIP withstands legal challenge, it would increase the cost of operating the customer facility serviced by MLMC.

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.

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The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at the North Dakota power plants.

In July 2024, the EPA issued a proposed partial denial of the state implementation plan.

We submitted comments to the EPA on the proposed partial denial during the third quarter of 2024 and have filed a petition for review with the Eight Circuit Court of Appeals.

The State of North Dakota, several of our customers, and others have also filed petitions for review.

On February 27, 2025, the EPA filed an unopposed motion to hold these consolidated cases in abeyance for 120 days while the new administration evaluates its position on the partial denial of the state implementation plan.

Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be

economically feasible for our North Dakota customers to invest in such equipment, which could result in early retirement of our customers' power plants and our associated mines.

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts.

These new rules may raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive, and/or result in early closure of the coal-fired EGU's operated by our customers which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of our coal mines.

We cannot predict the full impact of the various GHG and CAA rules on the operations of the coal-fired EGUs operated by our customers and any early closure of our mines could have a material adverse effect on our business, financial condition and results of operations.

The Trump administration is expected to direct the EPA to reconsider and revise or rescind the EPA’s rules regulating emissions from power plants, among other regulatory actions affecting power generation, and has already issued executive orders aimed at this outcome.

It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed.

Although we anticipate the EPA’s review of such regulations likely will result in less stringent requirements, we cannot predict the outcome of any final EPA actions or court challenges to such final actions.

Clean Water Act

CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for wastewater

discharge, including from coal mines.

In 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 for operations in waters of the United States (WOTUS.) On May 25, 2023, the SCOTUS issued its Sackett vs.

EPA ruling that defined WOTUS as “a relatively permanent body of water connected to traditional interstate navigable waters” with a “continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.” As a result of the Sackett decision, the EPA and the Army Corps of Engineers authored a revised definition of WOTUS and promulgated a final rule.

The new rule does not go into effect in states where a stay had been issued for the previous rule, including North Dakota, Texas, Louisiana, and Mississippi.

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 the meantime, securing CWA permits may be more challenging since the agencies in the states where a stay has been issued have less guidance to rely on to determine whether certain features are considered WOTUS.

To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our coal mining operations.

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 Protection that it was required to establish a mine water treatment trust to serve as a long-term funding mechanism related to this obligation.

In 2004, Bellaire was notified by the Pennsylvania Department of Environmental

Protection that it was required to establish a mine water treatment trust to serve as a long-term funding mechanism related to this obligation.

See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.

These federal and state requirements could require more costly water treatment and could materially adversely affect our business, financial condition and results of operations.

Resource Conservation and Recovery Act

RCRA affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including

hazardous wastes.

Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous

waste management.

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.

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In May 2023, the EPA published proposed regulations that would impose federal regulatory requirements for previously

exempt inactive CCR surface impoundments at inactive facilities (legacy CCR surface impoundments).

In May 2024, the EPA published a final rule amending CCR regulations which introduces new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired power plants with a legacy surface impoundment.

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.

These rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of our mines.

Any such closure of our mines could have a material adverse effect on our business, financial condition and results of operations.

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 the first quarter of 2023, the EPA proposed to deny the owner’s application.

The owner and other parties have submitted additional information and comments supporting the owner’s position.

If the EPA ultimately denies the owner’s application, a new liner may need to be installed or new waste management processes and/or units may need to be constructed.

Accordingly, it is possible that a denial by the EPA could require a temporary unit shut down.

Any temporary unit shut down could result in a temporary suspension of operations at Coal Creek Station.

To minimize any impact to operations, Coal Creek Station continues to work with the EPA and is moving forward with plans to dry CCR materials produced by the plant, reducing the need to utilize the lined area in question.

Falkirk is the sole supplier of lignite coal to Coal Creek Station.

Any suspension of operations at Coal Creek Station would eliminate the need for lignite coal during the suspension period.

Any such suspension of operations at Coal Creek Station or any of the power plants supplied by our mines could have a material adverse effect on our business, financial condition and results of operations.

National Environmental Policy Act

NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental

assessment or an environmental impact statement.

There are certain actions associated with surface coal mining that may trigger

these types of assessments by federal agencies.

When a NEPA action is required, we provide the required

information to the appropriate federal agency to enable it to complete the required study.

Historically, this process has been

lengthy and may take several years to complete.

In January 2023, the White House Council on Environmental Quality (CEQ)

issued interim guidance that instructs federal agencies to quantify GHG emissions and use the social cost of greenhouse gases to calculate a monetary metric associated with the proposed actions’ climate effects.

The NEPA and interim guidance could adversely affect our ability to secure necessary permits.

On June 3, 2023, President Biden signed the Fiscal Responsibility Act of 2023 into law, which included certain provisions

collectively known as the Builder Act.

The Builder Act includes amendments to NEPA which codify past regulatory reforms,

including narrowing what qualifies as a major federal action, limiting the scope of NEPA review to “reasonably foreseeable

environmental effects,” narrowing consideration of cumulative effects, directing agencies to only consider technically and

economically feasible reasonable alternatives and providing page limits and timelines for environmental impact statements and

environmental assessments.

In April 2024, the CEQ finalized the revised NEPA rules.

On February 16, 2025, CEQ issued a notice that it intends to rescind all CEQ NEPA implementing regulations.

These actions have raised significant questions regarding how CEQ’s NEPA regulations and agency-specific NEPA procedures will be interpreted and enforced going forward.

We are unable to predict what impact the new CEQ guidance will have on our ability to obtain governmental permits.

Federal Coal Leasing

We enter into leases of Federally owned coal for a small portion of the coal mined at certain of our North Dakota mines.

In July 2024, the Department of Interior’s Bureau of Land Management (BLM) published its North Dakota Proposed Resource Management Plan (RMP), which provided that no Federal coal which lies more than four miles away from a currently existing surface coal mining permit will be available for future leasing in North Dakota.

In September 2024, the Company, along with other stakeholders, including the Governor of North Dakota, filed protests against the RMP.

The BLM denied the protests and published the final RMP in January 2025.

The State of North Dakota filed a challenge to the RMP in the United States District Court for the District of North Dakota on February 25, 2025.

We are currently evaluating a similar challenge.

If any such challenges are not successful, we may be required to alter our mine plans to avoid areas of Federal coal in the future.

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.

Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.

Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry, some of which carry substantial penalties for failure to comply.

Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar assets.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas.

The interstate transportation of oil and natural gas and the sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (FERC).

Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation.

FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation.

We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment.

Sales of crude oil, condensate and natural gas liquids (NGLs) are not currently regulated and are made at market prices.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety.

These laws and regulations have the potential to impact production on our mineral interests, which could materially adversely affect the Minerals Management segment.

Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance.

These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations.

The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on our mineral interests, regardless of fault.

Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

In December 2023, EPA finalized a rule that will require oil and gas producers to reduce methane and other air pollutants from existing sources.

Oil and gas companies will be required to phase out routine flaring of natural gas and install methane leak detection equipment.

In May 2024, the EPA finalized a rule containing revisions and additions to the New Source Performance Standards (NSPS) program rules (the Final Methane Rule).

The Final Methane Rule formally reinstates emission limitations on methane, a GHG emission, for existing and modified facilities in the oil and gas sector.

Specifically, the Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities.

Several states and industry groups have filed suit before the D.C.

Circuit challenging the Final Methane Rule.

On October 4, 2024, the SCOTUS denied applications for an immediate stay of the Final Methane Rule pending review by the D.C.

Circuit Court of Appeals.

Though the final outcome is uncertain, the rule establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources.

The Final Methane Rule could have a significant impact on the upstream and midstream oil and gas sectors.

In November 2024, the EPA announced a final rule to reduce methane emissions from the oil and gas sector.

The rule requires payment of a Waste Emissions Charge (WEC) on waste emissions of methane from certain oil and gas facilities.

The Inflation Reduction Act-mandated fee would be triggered when companies report more than 25 metric tons of carbon dioxide equivalent per year to the EPA's Greenhouse Gas Reporting Program.

The fee begins at $900 per metric ton of methane exceeding that threshold in 2024 and increases over time.

A petition for review was filed in January 2025 by a coalition of Texas-led states and other industry groups.

The fee could have a significant impact on the upstream and midstream oil and gas sectors.

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.

Drilling and Production

The operations of the Minerals Management segment’s third-party lessees and our equity method investee are subject to various types of regulation at the federal, state and local level.

These types of regulation include requiring permits for the drilling of

wells, drilling bonds and generating reports concerning operations.

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:

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Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment.

The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our mineral interests, negatively affect the economics of production from these wells or limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our mineral and royalty interests operate.

Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Although the U.S.

Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

On January 20, 2025, President Trump issued several executive orders that prioritized energy security, exploration and production on federal lands and processing of Liquefied Natural Gas export applications.

Implementation of these executive orders could positively impact domestic drilling and production of oil and natural gas.

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

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales.

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 CWA regulates the underground injection of substances through the Underground Injection Control (UIC) program.

Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids.

The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011.

The 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.

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and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater.

The well integrity rule took effect in January 2014.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally.

A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing

If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs.

Such legislative or regulatory changes could cause operators of the operation on the acreage underlying our mineral interests, including those held by our equity method investee, to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying our mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations could adversely impact their operations.

Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

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.

Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells.

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.

Endangered Species Act

The Endangered Species Act (ESA) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats.

Pursuant to a settlement with environmental groups, the U.S.

Fish and Wildlife Service (USFWS) was required to determine whether over 250 species required listing as threatened or endangered under the ESA.

USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA.

Some of our properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold interests.

For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA.

Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states.

The listing of either of these species, or any others, in areas where we hold mineral interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas.

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978.

Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales.

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity.

Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas.

Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.

FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

However, the natural gas industry historically has been very heavily regulated;

therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA.

Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices.

Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation.

The transportation of oil in common carrier pipelines is also subject to rate regulation.

FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.

The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis.

Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates.

When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs.

Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as they are to our competitors.

State Regulation

States regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both.

States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot be certain that they will not do so in the future.

The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells and to limit the number of drilled wells or locations of our third-party lessee operators or of our equity method investment.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws.

Some of those laws relate to resource conservation and equal employment opportunity.

We do not believe that compliance with these laws will have a material adverse effect on our results of operations or financial condition.

Comprehensive Environmental Response, Compensation and Liability Act

CERCLA and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources.

We must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

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

The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites.

As a result, we may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect our results of operations and financial condition.

In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations.

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.

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.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

6 unchanged sentences

Neumann 50 Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to 2020)

Maxwell 47 Senior Vice President - Financial Planning and Analysis and Treasurer (from prior to 2019)

Maxwell 48 Senior Vice President - Finance and Treasurer (from prior to 2020)

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

6 unchanged sentences

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

What changed 10-K

Item 1. Business