What changed in this filing

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Item 1. Business

2024-03-06 compared with 2023-03-15 · 325 added, 248 removed, 396 unchanged (59% of the section changed)

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Mitigation Resources of North America ® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire").

The Company has 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 and other developing businesses.

Bellaire manages the Company’s long-term liabilities related to former Eastern U.S.

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

NACCO continues to focus on the execution of its two key strategies – Protect the Core and Grow and Diversify.

Management continues to be optimistic about the long-term outlook in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business.

Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations.

NAMining remains committed to expanding its business while improving operating efficiencies and scalability.

NAMining continues to work with Lithium Americas to develop the Thacker Pass Project in northern Nevada, one of the largest lithium projects in the United States.

The Company believes NAMining can grow to be a substantial contributor to operating profit over time, but the pace of growth will be dependent on the mix and scale of new projects and the successful implementation of projects to return NAMining to profitability.

The Minerals Management segment continues to pursue acquisitions of mineral and royalty interests in the United States.

Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a proven business model and a strong network to source and secure new acquisitions.

The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth.

The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as development costs are borne entirely by third-party producers who lease the minerals.

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

Mitigation Resources creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation and environmental restoration.

Management continues to view the long-term business outlook for NACCO positively.

The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses.

The Minerals Management segment, through the Company’s Catapult business unit, is focused on maximizing the value of existing mineral and royalty assets while it continues to pursue expansion of its asset base through acquisitions of additional mineral and royalty interests.

The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that delivers near-term cash flow yields and long-term projected growth.

The Company believes this business will provide unlevered after-tax returns on invested capital in the mid-teens as this business model matures.

This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development as these costs are borne entirely by third-party exploration and development companies that lease the minerals.

The Company is also considering additional investment opportunities, including non-operating working interests, as it continues to pursue diversification of revenue streams.

NAMining continues to focus on profit improvement initiatives as well as growth through additional business development activities.

NAMining is targeting potential customers who require a broad range of minerals and materials where it can leverage the Company’s core mining skills.

The goal is to build NAMining into a leading provider of contract mining services for customers who produce a wide variety of minerals and materials.

NAMining intends to be a substantial contributor to operating profit over time, including in its Sawtooth Mining subsidiary when production commences at Thacker Pass, which is targeting initial production in late 2026.

Once production commences, Sawtooth Mining Company, LLC ("Sawtooth") will receive a management fee per metric ton of lithium delivered.

The pace of achieving substantially improved results at NAMining will depend on the execution and successful implementation of profit improvement initiatives in the aggregates operations, and the mix and scale of new projects.

A number of initiatives have already delivered improved financial results.

Mitigation Resources continues to develop its business, which creates and sells stream and wetland mitigation credits, provides services to those engaged in permittee-responsible mitigation and provides mine reclamation and other environmental restoration services.

This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation.

During 2022, Mitigation Resources purchased property near Dallas-Fort Worth, Texas and near Nashville, Tennessee to establish new mitigation banks.

In addition, it established a joint venture to provide mitigation services for the Lake Ralph Hall reservoir project in North Texas.

As of December 31, 2022, Mitigation Resources is involved in over 10 mitigation banks and permittee-responsible mitigation projects in Tennessee, Alabama, Mississippi and Texas.

With additional projects in its pipeline for 2023, Mitigation Resources is making strong progress toward its goal to be a top ten provider of stream and wetland mitigation services in the southeastern United States.

The Company believes that Mitigation Resources can provide solid rates of return as this business matures.

The Company continues to pursue activities which can strengthen the resiliency of its existing coal mining operations.

Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine

locations to help customers with management fee contracts be more competitive.

These activities benefit both customers and

the Company's Coal Mining segment, since fuel cost is a significant driver for power plant dispatch.

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

Fluctuating natural gas prices and

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

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding

unnecessary risk.

Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses.

The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering

focus on safety and environmental stewardship.

Mitigation Resources is making strong progress toward its goal of becoming a top ten provider of stream and wetland mitigation services in the southeastern United States.

The Company believes that Mitigation Resources can provide solid rates of return on capital employed as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations.

The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive.

These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch.

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

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

While the Company realizes the coal mining industry faces political and regulatory challenges and

demand for coal is projected to decline over the longer-term, the Company believes coal should be an essential part of the energy mix in the United States for the foreseeable future.

The Company continues to look for ways to create additional value by utilizing its core mining competencies around reclamation and permitting through the development of utility-scale solar projects.

Reclaimed mining properties offer large tracts of land that could be well-suited for solar and other energy-related projects.

These projects could be developed by the Company itself or through joint ventures that include partners with expertise in energy development projects.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk.

Strategic diversification is designed to generate cash that can be re-invested to strengthen and expand the businesses.

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

Business Developments

Mississippi Lignite Mining Company ("MLMC") is the exclusive supplier of lignite to the Red Hills Power Plant in Ackerman, Mississippi.

Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement.

CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant.

During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment.

If lease payments are not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant.

Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary.

On October 27, 2022, Southern Company disclosed in its Form 10-Q that it provided notice to the lessee, CGLP, to terminate the related operating and maintenance agreement effective June 30, 2023.

CGLP failed to make the semi-annual lease payment due December 15, 2022.

As a result, the Southern Company subsidiary was unable to make its corresponding payment to the debtholders.

The parties to the lease agreement are currently negotiating a potential restructuring, which could result in rescission of the termination notice.

The parties to the lease have entered into a forbearance agreement which suspends the related contractual rights of the parties while they continue restructuring negotiations.

The ultimate outcome of this matter cannot be determined at this time but could have a material impact on the Company's financial statements if the operating and maintenance agreement is terminated.

On December 18, 2023, Mississippi Lignite Mining Company ("MLMC") received a force majeure event notice from its customer related to an issue that began on December 15, 2023 and impacted one of two boilers at the Red Hills Power Plant.

The notice did not provide a timeline for resolution of the issue.

As of March 6, 2024, the impacted boiler is still not operational.

The prolonged mechanical issue is expected to result in a reduction in customer demand and will have a significant impact on the Company's results of operations during 2024.

The Company determined the anticipated reduction in customer demand caused by this issue was an indicator of potential impairment.

The Company reviewed MLMC's long-lived assets for impairment as of December 31, 2023 and determined the carrying amount of its long-lived assets were not recoverable.

As a result, the Company recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023.

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

During 2023, Minerals Management, through Catapult, completed an acquisition of $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin.

During 2022, Catapult acquired $11.4 million of mineral and royalty interests in the Texas portion of the Permian Basin and the Wyoming portion of the Powder River Basin as well as a small acquisition of mineral interests in the New Mexico portion of the Permian Basin.

During December 2023, NAMining executed a 15-year contract to mine phosphate at a quarry in central Florida.

Production is expected to commence in the first half of 2024 once relocation and commissioning of a dragline is complete.

NAMining also amended and extended existing limestone contracts with two customers and expanded the scope of work with another customer.

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 final reclamation began 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.

On October 1, 2026, SWEPCO will acquire all of the capital stock of Sabine and complete the remaining mine reclamation.

The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota.

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

Coal Creek Station was previously owned by Great River Energy (“GRE”).

On May 2, 2022, GRE completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates.

As a result of the completion of the sale of Coal Creek Station, the Coal Sales Agreement, the Mortgage and Security Agreement and the Option Agreement between GRE and Falkirk were terminated.

On May 2, 2022, Great River Energy ("GRE") completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates.

The Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy became effective upon the closing of the transaction.

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The initial production period is expected to run through May 1, 2032, but the CSA may be extended or terminated early under certain circumstances.

The Company recognized $30.9 million in the second quarter of 2022 as GRE paid NACoal $14.0 million in cash, transferred ownership of an office building with an estimated fair value of $4.1 million, and conveyed membership units in Midwest AgEnergy Group, LLC (“MAG”), a North Dakota-based ethanol business, with an estimated fair value of $12.8 million, as agreed to under the termination and release of claims agreement between Falkirk and GRE.

The Company recognized a gain of $30.9 million during 2022 as GRE paid the Company cash, transferred ownership of an office building, and conveyed membership units in Midwest AgEnergy Group, LLC (“MAG”), a North Dakota-based ethanol business as agreed to under the termination and release of claims agreement between Falkirk and GRE.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG.

On December 1, 2022, HLCP Ethanol Holdco, LLC (“HLCP”) completed its acquisition of MAG.

Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million.

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

All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W.

Pirkey Plant (the “Pirkey Plant”).

SWEPCO is an American Electric Power (“AEP”) company.

AEP intends to retire the Pirkey Plant during March 2023.

Sabine expects deliveries to cease in March 2023 and final reclamation to begin on April 1, 2023.

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

In 2022, Minerals Management, through its Catapult business, completed two acquisitions.

It acquired $11.4 million of mineral

and royalty interests in the Texas portion of the Permian Basin and the Wyoming portion of the Powder River Basin.

It also completed a small acquisition of mineral interests in the New Mexico portion of the Permian Basin.

Upon closing of the transaction, NACCO

transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million during 2022.

The Company received additional payments totaling $3.6 million during 2023 in connection with a post-closing purchase price adjustment and the release of amounts held in escrow.

During 2023, the Board of Directors of the Company approved the termination of the Combined Defined Benefit Plan for NACCO and its subsidiaries (the “Combined Plan”) and Combined Plan participants were offered lump-sum distributions as part of the termination process.

As a result of the lump-sum distributions, the Company recognized a non-cash, pension settlement charge of $1.8 million.

See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.

In December 2023, the Company 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 the Company’s Red Hills Mine.

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

In addition, the Company will enter into an engineering, procurement and construction agreement related to development of the project.

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

Coal Mining Segment

The Coal Mining segment, operating as The North American Coal Corporation ® ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model.

Lignite coal is surface mined in North Dakota, Texas and Mississippi.

Each mine is fully integrated with its customer's operations and is the exclusive supplier of coal to its customer's facilities.

During 2022, the Coal Mining segment's operating coal mines were:

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

The Coal Mining segment, operating as North American Coal, LLC, 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 its customer's operations.

As of December 31, 2023, the Coal Mining segment's operating coal mines were:

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

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

MLMC’s coal supply contract contains a take or pay provision;

all other coal supply contracts are requirements contracts under which earnings can fluctuate.

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

all other coal supply contracts are requirements contracts.

Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

At Coteau, Coyote Creek, Falkirk and Sabine, the Company is paid a management fee per ton of coal or heating unit (MMBtu)

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation;

therefore, MLMC is consolidated within NACCO’s financial statements.

MLMC sells coal to its customer's Red Hills Power Plant 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.

The Red Hills Power Plant supplies electricity to TVA under a long-term power purchase agreement.

MLMC’s contract with its customer runs through April 1, 2032.

TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables.

The decision regarding which power plants to dispatch is determined by TVA.

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

During 2023, MLMC completed mining in its original mine area and began mining in a new mine area.

The move to the new mine area resulted in increased costs during 2023.

MLMC does not anticipate opening additional mine areas through the remaining contract term unless doing so would result in improved economic returns.

On December 18, 2023, MLMC received a force majeure event notice from its customer related to an issue that began on December 15, 2023 and impacted one of two boilers at the Red Hills Power Plant.

The notice did not provide a timeline for resolution of the issue.

As of March 6, 2024, the impacted boiler is still not operational.

The prolonged mechanical issue is expected to result in a reduction in customer demand and will have a significant impact on the Company's results of operations during 2024.

The Company determined the anticipated reduction in customer demand caused by this issue was an indicator of potential impairment.

The Company reviewed MLMC's long-lived assets for impairment as of December 31, 2023 and determined the carrying amount of its long-lived assets were not recoverable.

As a result, the Company recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023.

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

At Coteau, Coyote Creek and Falkirk, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered.

Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad

measures of U.S.

The 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

Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to

NACCO and NACoal.

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

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

Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to the Company.

See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

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See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

While Falkirk meets the definition of a VIE, the completion of the Rainbow Energy transaction resulted in a VIE

reconsideration event.

As the terms of the CSA between Falkirk and Rainbow Energy are substantially the same as the terms

of the coal supply contract between Falkirk and GRE, Falkirk remains a VIE and Rainbow Energy is the primary beneficiary;

therefore, NACCO will continue to account for Falkirk under the equity method.

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations.

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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.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation;

therefore, MLMC is consolidated within NACCO’s financial statements.

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

inflation rates.

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

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

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi.

The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA").

MLMC’s contract with its

customer runs through 2032.

TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables.

The decision of which power plants to dispatch is determined by TVA.

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

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

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materials handling and processing, product sales and distribution.

NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers.

As of December 31, 2022, NAMining operates mines in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

As of December 31, 2023, NAMining operates in Florida, Texas, Arkansas, Virginia and Nebraska.

In addition, Sawtooth Mining, LLC ("Sawtooth") provides mining design, consulting and will be the exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries.

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

The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests and overriding royalty interests.

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

• Royalty Interest.

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The holder of a mineral interest has the right to lease the minerals to an exploration and production company.

Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

Upon the execution of an oil and gas lease, the lessee (the

exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

• Non-Participating Royalty Interest (“NPRIs”).

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Total consideration for the 2023 and 2022 acquisitions of mineral and royalty interests was $36.7 million and $11.9 million, respectively.

The 2023 acquisition includes 43.4 thousand gross acres and 2.5 thousand net royalty acres.

The 2022 acquisitions included 13.6 thousand gross acres and 880 net royalty acres.

The 2021 acquisitions included 20.6 thousand gross acres and 1.8 thousand net royalty acres.

Total mineral and royalty interests included approximately 141.4 thousand gross acres and 60.8 thousand net royalty acres at December 31, 2022.

The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) existing producing wells further along the decline curve that will generate stable cash flow.

Total mineral and royalty interests include approximately 184.7 thousand gross acres and 63.3 thousand net royalty acres at December 31, 2023.

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

The Company's acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition and (iii) existing producing wells further along the decline curve that will generate stable cash flow.

In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian basin and a secondary focus on other diversifying basins to increase regional exposure.

While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in ORRIs, NPRIs or non-operated working interests under certain circumstances.

While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in ORRIs, NPRIs or non-operating working interests under certain circumstances.

The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator.

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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, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

As a mineral owner, the Company has limited access to timely information, involvement, and

operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

In 2023 and 2022, two customers individually accounted for more than 10% of consolidated revenues.

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

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

The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include

conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems.

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

The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems.

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

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

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

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 the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions.

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

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

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

Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term.

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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 generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal.

Sustained higher natural gas prices could lead to increased demand for coal and positively affect the Coal Mining segment results.

Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind and solar.

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, the Company continues 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 8 in this Form 10-K for further discussion.

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

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.

The Company has experienced limited variability in its results due to the effect of seasonality;

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Decline rates can vary due to factors like well depth, well length, geology, formation pressure, and facility design.

production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

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

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities.

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

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

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

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

Human Capital

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NACCO believes its employees are critical to its success and invests in its employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives.

The Company offers a 100% 401(k) matching contribution up to 5% of compensation and a generous profit-sharing contribution for all of our full-time and part-time employees.

The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location.

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The Company has earned more than 100 safety awards at the state and national levels.

NACCO strives to have zero safety incidents or injuries.

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

Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety.

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

Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services.

Some laws, as discussed below, place many requirements on the Company's operations and its customers' operations.

Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.

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

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

Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently

increases the regulatory burden on affected members of the industry and could affect the results of the Company’s Minerals Management segment.

Mine Health and Safety Laws

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The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits.

however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000.

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations.

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The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit.

These obligations are largely unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

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.

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The Company does not believe there is any significant risk to the Company's subsidiaries' ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.

Greenhouse Gas (“GHG”) Emissions

In July 2019, the EPA finalized a rule that repealed the Clean Power Plan ("CPP") that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (“ACE”) rule.

The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units (“EGUs”).

In response to challenges brought by environmental groups and certain states, the U.S.

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

Circuit Court”) vacated the ACE rule, including its repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action.

On June 30, 2022, the Supreme Court of the United States (“SCOTUS”) issued an opinion reversing the D.C.

Circuit Court's decision, and finding that the EPA exceeded its statutory authority when it adopted the CPP.

On May 11, 2023, the EPA published a draft rule imposing limits on GHG emissions from existing coal and new natural-gas electric generating units, which could compel such facilities to install additional pollution controls or shut down ("CPP2").

The proposed CPP2 includes guidelines for carbon dioxide ("CO2") emissions from existing EGUs with a proposed compliance

date of January 1, 2030.

For coal-fired steam EGUs that plan to operate past January 1, 2040, the EPA is proposing a best

system of emissions reduction ("BSER") of carbon capture and sequestration/storage ("CCS") with 90 percent capture of CO2

at the stack.

For coal-fired steam EGUs that will permanently cease operations after December 31, 2031, but before January 1,

2040, the EPA is proposing a BSER of 40 percent natural gas co-firing on a heat input basis.

Coal-fired steam EGUs that will permanently cease operations between December 31, 2031 and January 1, 2035, will be subject to an annual capacity factor

limit, and for units that will permanently cease operations before January 1, 2032, the EPA is proposing a BSER of routine

methods of operation and maintenance that maintain current emission rates.

Each of the EGUs supplied by the Company would

be subject to these proposed requirements.

Additionally, the proposed CPP2 contains other actions, including revised new source performance standards for GHG

emissions from new and reconstructed fossil fuel-fired steam EGUs that undertake a large modification.

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

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 the Company's coal mines.

Any such closure of the Company's mines could have a material adverse

effect on the Company’s business, financial condition and results of operations.

Clean Air Act

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

The 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.

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

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Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.

States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA.

The 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 revisions.

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

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

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.

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

In March 2019, the EPA

published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides ("SOx") without revision.

The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years.

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

This affects states in the eastern half of the U.S.

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

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

Phase II reductions became effective in 2017.

In 2016, the EPA mandated additional reductions in nitrogen oxide emissions.

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

Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines.

In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards.

Court of Appeals for the D.C.

Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards.

None of the power plants supplied by the Company are within non-attainment areas for ozone.

In March 2022, the EPA announced a federal plan to “help states fully resolve their Clean Air Act ‘good neighbor’ obligations for the 2015 ozone NAAQS.

This new plan would double the number of covered states and require daily limits on emissions from large coal-fired power plants.

The plan would also broaden the existing nitrogen oxides power plant trading program from 12 states to 25 during the summertime ozone season while also ratcheting down nitrogen oxides caps for states, starting in 2023.

If this plan is finalized as proposed, it could have a material adverse effect on the Company’s business, financial condition or results of operations.

The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”).

The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants.

The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.

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

The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour sulfur dioxide concentrations, averaged over 3 years.

On January 6, 2023, the EPA proposed to lower the level of the particulate matter.

If enacted as proposed, this rule would require fossil fuel generating units to install additional

emission reducing technologies, which will ultimately increase the cost of fossil fuel generated energy or cause potential EGU retirements.

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

While the CSAPR affects states in the eastern half of the U.S.

and Texas, it does not affect EGUs in North Dakota.

This rule imposes

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

The EPA began

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

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

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

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

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

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

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

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

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

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

In December 2023, the SCOTUS agreed to hear a challenge to the FIP.

The case was heard in February 2024 and will be decided later in the year.

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.

The Company cannot predict the outcome of the legal challenges to the:

(i) various state challenges;

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

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

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants.

In December 2011, the EPA

adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired

This rule requires mercury emission reductions in mercury-containing particulate matter.

On March 6, 2023, the EPA concluded that it is appropriate and necessary to regulate mercury-containing particulate matter.

In April 2023, the EPA drafted proposed revisions to MATS.

These revisions would remove the mercury emission limit for lignite-fired EGUs and require particulate emission reductions for all coal-fired EGUs.

If enacted as proposed, this rule could influence the closure of additional coal-fired EGUs, potentially including all of the EGUs supplied by the Company.

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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In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period.

In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary.

The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions.

Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits.

In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019.

While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021.

Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized.

SIPs have been sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and Wildlife Service and the United States Forest Service and all corresponding public comment periods.

State implementation of the EPA’s Regional Haze Rule could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could result in the premature closure of the power plant and the Coyote Creek mine.

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Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be economically feasible for Coyote Creek's customers to invest in such equipment, which could result in early retirement of Coyote Station and the Coyote Creek mine.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”).

In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S.

alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards.

Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants.

The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources.

Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner

or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds.

The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”.

In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule;

however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “NSR program”).

Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds.

Both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant

emission increase”.

Uncertainty around the NSR program rules could adversely impact demand for coal.

Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants.

In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units.

This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program.

These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal.

If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA

requirements, including the requirements under MATS and the EPA's regional haze program.

These costs raise the price of

coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand

If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or

if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations

could be materially adversely affected.

Global climate change continues to attract considerable attention in the United States.

Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants.

Congress has considered climate change legislation aimed at reducing GHG emissions, particularly from coal combustion by power plants.

Enactment of laws and passage of regulations regarding GHG emissions by the U.S.

or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

or States, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels.

These proposals include emission taxes, emission reductions, including carbon tax and “cap-and-trade” programs, and mandates or incentives to generate electricity by using renewable resources, such as wind or solar power.

Some states have established programs to reduce GHG emissions.

Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare.

Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants.

In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs").

In contrast to the Clean Power Plan, which preceded the ACE rule, the ACE rule limited "best system of emission reduction" to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU.

The ACE rule was challenged by a suite of petitioners before the U.S.

Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and vacated the ACE rule.

In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants.

In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States granted certiorari.

In June 2022, the U.S.

Supreme Court reversed the D.C.

Circuit’s decision on the ACE rule and remanded the case back to the D.C.

The EPA has indicated that it will draft a new rule to regulate carbon dioxide emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company’s business, financial condition or results of operations.

The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code.

The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021.

The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025.

Solar energy property placed in service after December 31, 2025 will receive a 10% ITC.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”).

The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions.

These incentives could further accelerate the transition of the U.S.

economy away from the use of fossil fuels and impact demand for fossil fuels.

The ultimate impact on fossil fuel demand and the Company is uncertain and may change as

implementation of the Inflation Reduction Act moves forward.

The subsidization of alternative energy sources may have a material adverse effect on the Company’s business, financial condition or results of operations.

has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005.

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The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions.

In November 2020, the United States formally withdrew from the Paris Agreement;

however, the United States rejoined in February 2021.

The United States is a party to the Paris Agreement.

The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a material adverse effect on the Company’s business, financial condition and results of operations.

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Clean Water Act

The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge.

Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water.

Waters discharged from coal mines are required to meet these standards.

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

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits.

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

discharge, including from coal mines.

These federal and state requirements could require more costly water treatment and could

materially adversely affect the Company’s business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance

with such permits.

In many instances, mining operations require securing CWA authorization or a permit from the U.S.

Army Corps of Engineers for operations in waters of the United States.

Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR").

The new definition was challenged in court and two court cases resulted in vacatur of the NWPR.

The Supreme Court of the United States heard the Sackett vs.

EPA case in October 2022 that challenges how federal jurisdiction of wetlands should be determined.

A decision is expected by June 2023.

In the meantime, in January 2023, the EPA published a new rule that redefines WOTUS that relies on the significant nexus test established by the 2006 Rapanos decision.

The new definition expands the scope of the federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands.

Corps of Engineers for operations in waters of the United States ("WOTUS.") The SCOTUS heard the Sackett vs.

EPA case in October 2022, which considered whether certain wetlands constitute WOTUS.

Prior to the SCOTUS issuing a decision, in January 2023, the EPA published a new rule that redefines WOTUS using an expansive significant nexus test.

The new definition expanded the scope of federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands.

The new WOTUS definition was ultimately stayed in 24 states, including Louisiana, Mississippi and North Dakota.

On May 25, 2023, the SCOTUS issued its Sackett vs.

EPA ruling that defines 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.” The SCOTUS decision rejected the “significant nexus” test used by the EPA in its 2023 WOTUS rule.

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 that removed references to “significant nexus”.

The new rule does not go into effect in states

where a stay had been issued for the previous rule, including North Dakota, Texas, Louisiana, and Mississippi.

In these states,

the legal challenge to the rule will resume.

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

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.

Bellaire was notified by the Pennsylvania Department of Environmental Protection during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water

treatment trust.

Bellaire was notified by the Pennsylvania Department of Environmental Protection during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust.

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

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes.

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

In 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste.

In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule.

One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care.

The second revision allows issuance of technical certifications in lieu of a professional engineer.

In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units.

In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction.

The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure:

(a) no later than October 17, 2023 for surface impoundments 40 acres or smaller;

and (b) October 17, 2028 for surface impoundments larger than 40 acres.

Additionally, the CCR Part B Final Rule allowed facilities to demonstrate that there is no reasonable probability of adverse effects to human health and the environment at non-conforming units.

These new 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 the Company's mines.

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

hazardous wastes.

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

waste management.

In 2020, the EPA finalized changes to the coal combustion residual ("CCR") rule that classified all clay-lined surface impoundments that receive CCR as unlined.

The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of disposal capacity with a deadline to initiate closure and a new site-specific alternative due to permanent cessation of coal-fired boilers with deadlines to complete closure.

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 the Company's mines.

Any such closure of the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE.

The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future.

In compliance with these regulations, the owner of the Coal Creek Station power plant, Falkirk’s customer, 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 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 the

Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

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).

If finalized as proposed,

it could increase the regulatory cost of compliance for the Company's customers thereby increasing the cost of power which

could materially adversely affect the Company’s business, financial condition and results of operations.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to OSMRE.

OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future.

The outcome of these rulemakings, and any subsequent actions by the EPA and OSMRE, could impact those Company operations that beneficially use CCRs.

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National Environmental Policy Act

NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement.

There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies.

When a NEPA action is required, the Company provides the required information to the appropriate federal agency so that they may complete the environmental assessment.

Historically, this process has been lengthy and may take several years to complete.

In 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations;

however, it was immediately challenged by states and non-governmental organizations.

In April 2022, the CEQ issued a new draft rule rescinding many of the revisions from the 2020 update.

In January 2023, the CEQ issued interim guidance that instructs federal agencies to quantify GHG emissions for each alternative and use the social cost of greenhouse gasses to calculate a monetary metric that gives decision makers and the public useful information and context about a proposed actions’ climate effects.

The revised NEPA regulations and interim guidance could adversely affect the Company’s ability to secure necessary permits.

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

assessment or an environmental impact statement.

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

these types of assessments by federal agencies.

When a NEPA action is required, the Company provides the required

information to the appropriate federal agency 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 the Company’s ability to secure necessary permits.

On April 21, 2023, President Biden signed a new executive order focused on incorporating environmental justice considerations

into federal decision-making.

The executive order created a new White House Office of Environmental Justice, and directed all federal agencies to make environmental justice a central part of each agency’s mission by publishing an environmental justice

strategic plan for the agency.

Additionally, the order requires agencies conducting NEPA reviews to assess direct, indirect and

cumulative impacts on environmental justice communities in their analyses, to consider best available science and information

on disparate health impacts related to exposure to environmental hazards and provide opportunities for meaningful engagement

with environmental justice communities during the environmental review process.

It largely remains to be seen how federal agencies will undertake to comply with these new requirements addressing environmental justice considerations, but the development and application of the new requirements may result in permit uncertainty and delays for activities that require federal approvals.

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.

It remains to be seen how the changes enacted by Congress will impact site level NEPA analysis.

Regulation of the Oil and Natural Gas Industry

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

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

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

The interstate transportation of oil and natural gas and the sale 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.

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.

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

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

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

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

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• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or "allowables";

• the rates of production;

• the surface use and restoration of properties upon which wells are drilled;

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

Army Corps of Engineers and many other state and local authorities also have

regulations for plugging and abandonment, decommissioning and site restoration.

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.

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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.

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

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

Some of the Company’s properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests.

Some of the Company’s properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened

species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests.

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

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State Regulation

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

Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production.

States 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.

For example, Texas currently imposes a 4.6% severance tax on the

market value of oil production and a 7.5% severance tax on the market value of natural gas production.

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

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

Other Regulations

The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”).

The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy sources, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions.

These incentives could further accelerate the transition of the U.S.

economy away from the use of fossil fuels and impact demand for fossil fuels.

The ultimate impact on fossil fuel demand and the Company is uncertain and may change as implementation of the Inflation Reduction Act moves forward.

The subsidization of alternative energy sources may have a material adverse effect on the Company’s business, financial condition or results of operations.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

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Name Age Current Position

62 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018)

Loveman 53 Vice President and Controller and Principal Financial Officer (from prior to 2018)

Neumann 47 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018)

Maxwell 45 Vice President - Financial Planning and Analysis and Treasurer (from prior to 2018)

63 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACCO Natural Resources Corporation ("NNRC") (from prior to 2018)

Loveman 54 Senior Vice President and Controller and Principal Financial Officer (from prior to 2018)

Neumann 48 Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to 2018)

Maxwell 46 Senior Vice President - Financial Planning and Analysis and Treasurer (from prior to 2018)

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name Age Current Position

62 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018)

Dewing 66 Vice President - Operations of NACoal (from prior to 2018)

Neumann 47 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018)

63 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NNRC (from prior to 2018)

Dewing 67 Senior Vice President and Chief Operating Officer of NNRC (from prior to 2018)

Neumann 48 Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to 2018)

Patrick Sullivan, Jr.

64 Vice President and Chief Financial Officer of NACoal (from prior to 2018)

65 Senior Vice President and Chief Financial Officer of NNRC (from prior to 2018)

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