What changed in this filing

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Item 1. Business

2023-03-15 compared with 2022-03-02 · 219 added, 238 removed, 425 unchanged (52% of the section changed)

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

The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer.

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

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

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

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

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

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").

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Business Strategy

During 2021, the Company launched a new branding campaign.

The new branding creates a unified identity and underscores NACCO’s commitment to all of its businesses, while focusing on the execution of its two key strategies – Protect the Core and Grow and Diversify.

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

The new branding provides each business with its own unique identity that can easily be linked back to the NACCO legacy brand and includes new websites for each business, including NACCO Natural Resources, new business-specific logos and a new tagline “Bringing Natural Resources to Life”.

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.

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

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.

NAMining is pursuing growth and diversification by expanding the scope of its business development activities to include potential customers who require a broad range of minerals and materials and by leveraging the Company’s core mining skills to expand the range of contract mining services it provides.

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.

The Company believes NAMining can grow to be a substantial contributor to operating profit, delivering unlevered after-tax returns on invested capital in the mid-teens as this business model matures and achieves significant scale, but the pace of achieving these objectives will be dependent on the mix and scale of new projects.

The Minerals Management segment continues to grow and diversify by selectively acquiring mineral and royalty interests in the United States, in a market and price environment that the Company believes remains well-aligned with its strategy and objectives.

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

The Company believes this business model can deliver substantial operating margins over the life of a reserve without the costs and risk that traditional oil and gas companies bear for the cost of exploration, production and/or development.

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 strong network to source and secure new acquisitions, and has several potential acquisitions under review.

The goal is to construct a diversified portfolio of high-quality oil and gas mineral and royalty interests in the United States that deliver 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 low-to-mid-teens as the portfolio of reserves and mineral interests grows and this business model matures.

Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation.

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

The Mitigation Resources business has achieved several early successes and is positioned for additional growth.

The Company's

goal is to grow Mitigation Resources into one of the ten largest U.S.

providers of mitigation solutions, largely focused on streams and wetlands, initially in the southeast United States.

While this business is in the early stages of development, the Company believes that Mitigation Resources can provide solid rates of return 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 and availability of renewable energy sources, such as wind and solar, affect the amount of electricity dispatched from coal-fired power plants.

Coal and natural gas traditionally have been the two largest sources of electricity generation in the United States.

In many areas of the country, these two fuels compete to supply electricity based on their relative costs.

natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal.

Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable.

During 2021, however, natural gas prices were much higher than in recent years, generally resulting in increased dispatch of coal-fired power plants.

The Company continues to look for opportunities to expand its coal mining business where it can apply its management fee business model to assume operation of existing surface coal mining operations in the United States.

However, opportunities are very limited in the current environment.

In addition, the political and regulatory environment is not receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines.

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

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.

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.

In all of its business endeavors, the Company continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety, environmental stewardship and people.

The Company is passionately committed to working hard, doing what’s right, and bringing America's natural resources to life.

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

Coal Mining Segment

Effective September 30, 2021, the contract mining agreement between Bisti Fuels Company, LLC (“Bisti”) and its customer, Navajo Transitional Energy Company ("NTEC") was terminated.

As required under the agreement, NTEC paid the Company a termination fee of $10.3 million.

As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.

The Coteau Properties Company (“Coteau”) operates the Freedom Mine in North Dakota.

All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative (“Basin Electric”).

Basin Electric utilizes the coal at the Great Plains Synfuels Plant (the “Synfuels Plant”), Antelope Valley Station and Leland Olds Station.

The Synfuels Plant is a coal gasification plant, owned by Dakota Gasification Company (“Dakota Gas’), a subsidiary of Basin Electric, that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale.

During 2020, Basin Electric informed Coteau that it is considering changes that may result in modifications to its Synfuels Plant that could potentially reduce or eliminate coal requirements at the Synfuels Plant.

During August 2021, Bakken Energy (“Bakken”) and Basin Electric signed a non-binding term sheet to transfer ownership of the assets of Dakota Gas to Bakken.

Bakken stated the closing date is expected to be April 1, 2023.

As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025.

The closing is subject to the satisfaction of specified conditions.

Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close.

Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026.

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.

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 pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant.

Coal Creek Station and Spiritwood Station are owned by Great River Energy (“GRE”).

In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas.

During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates.

closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.

Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will terminate.

Falkirk and GRE have entered into a termination and release of claims agreement.

Upon completion of the sale of Coal Creek Station, GRE will pay Falkirk $14.0 million in cash, as well as transfer ownership of an office building located in Bismarck, North Dakota, and convey membership units in Midwest AgEnergy to The North American Coal Corporation® (“NACoal”), a wholly-owned subsidiary of NACCO.

NACCO currently holds a $5.0 million investment in Midwest AgEnergy, which operates two ethanol facilities in North Dakota.

If GRE's efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will supply all coal requirements of Coal Creek Station concurrent with Rainbow Energy’s acquisition of the power plant.

Falkirk will no longer make any coal deliveries to GRE’s Spiritwood Station.

Falkirk will be paid a management fee and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine.

The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy.

The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances.

If Rainbow Energy terminates the CSA and closes Coal Creek Station before 2027, Falkirk will be entitled to an additional payment from GRE under the terms of the termination and release of claims agreement.

The additional payment amount ranges from $8 million if the closure occurs before 2024 to $2 million if the closure occurs in 2026.

To support the transfer to new ownership, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA through May 31, 2024.

After May 31, 2024, the per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S.

If GRE’s efforts to sell the power plant are not successful and GRE elects to prematurely close Coal Creek Station, the early termination of the CSA would have a material adverse effect on the Company's business, financial condition and results of operations.

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.

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

Falkirk continues to supply all coal requirements of Coal Creek Station and is paid a management fee per ton of coal delivered.

To support the transfer to new ownership, Falkirk agreed to a reduction in the current per ton management fee from the effective date of the CSA through May 31, 2024.

After May 31, 2024, the per ton management fee increases to a higher base in line with 2021 fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S.

Rainbow Energy is responsible for funding all mine operating costs, including mine reclamation, and directly or indirectly providing all of the capital required to operate the mine.

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.

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.

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

During 2020, AEP announced its intent to retire the Pirkey Plant in 2023.

SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation.

Funding for mine reclamation is the responsibility of SWEPCO.

During 2020, Caddo Creek Resources Company, LLC (“Caddo Creek”) ceased all mining and delivery of lignite and commenced mine reclamation.

Funding for mine reclamation is the responsibility of a subsidiary of Advanced Emissions Solutions (“AES”).

Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation.

The reclamation at Caddo Creek is expected to be substantially complete during the first half of 2022.

During 2020, the contract mining agreement between Camino Real Fuels, LLC (“Camino Real”) and its customer, Dos Republicas Coal Partnership (“DRCP”), terminated and resulted in mine closure.

Funding for mine reclamation is the responsibility of DRCP.

NAMining Segment

In the third quarter of 2021, NAMining entered into contracts with a new customer to perform all mining operations at two sand and gravel quarries located in Texas and Arkansas.

The initial term of each contract is two years, and one of the contracts automatically extends an additional two years provided NAMining is not in default under that contract.

In the second quarter of 2021, NAMining entered into a one-year mining services contract with an existing customer for a sand and gravel quarry in Indiana.

In the first quarter of 2021, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida.

NAMining will operate two smaller draglines at this quarry while it relocates and commissions a larger dragline that will increase production capacity.

The relocated dragline is anticipated to be commissioned in the second half of 2022.

During 2021, NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida.

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

Thacker Pass is owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp.

Lithium Americas Corp.

owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium

At maturity, the Thacker Pass management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

Minerals Management Segment

During 2021 and 2020, the Minerals Management segment acquired additional mineral interests, primarily in the Eagle Ford and Permian Basins in Texas.

During the second quarter of 2021, the Minerals Management segment, through its Catapult business, acquired a combination of mineral and overriding royalty interests in the Eagle Ford Basin, which includes approximately 14.1 thousand gross acres and 1.7 thousand net royalty acres, for an initial payment of $4.7 million.

Under the terms of the transaction, Catapult could make additional payments for each additional well developed on the acquired assets during 2022 of up to a maximum of $0.6 million.

Catapult also completed a small acquisition of royalty interests in the Delaware Basin during 2021 for a purchase price of $0.3 million.

Minerals Management intends to continue to make future acquisitions of mineral and royalty interests that meet the Company’s acquisition criteria as part of its growth strategy.

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.

Coal Mining Segment

The Coal Mining segment, NACoal, operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model.

Coal is surface mined in North Dakota, Texas, Mississippi and Louisiana.

Through September 30, 2021, the Company provided contract mining services on the Navajo Nation in New Mexico.

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

During 2021, the Company's operating coal mines were:

Bisti, Coteau, Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), Falkirk, Mississippi Lignite Mining Company (“MLMC”) and Sabine.

Coteau, Coyote, Falkirk, MLMC and Sabine supply lignite coal for power generation.

Demery supplies lignite coal for the production of activated carbon products.

Each mine is the exclusive supplier of coal to its customers' facilities.

Each of these mines delivers its coal production to adjacent or nearby power plants, synfuels plants or an activated carbon processing facility under long-term supply contracts.

MLMC’s lignite sales agreement contains a minimum annual take provision;

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

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.

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.

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

At all operating coal mines other than MLMC, 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 provide all of the capital required to build and operate the mine.

This contract structure eliminates the Company's 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 NACCO and NACoal.

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

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.

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

All operating coal mines other than MLMC meet the definition of a variable interest entity (“VIE”).

In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control;

therefore, NACCO does not consolidate the results of these operations within its financial statements.

Instead, these contracts are accounted for as equity method investments.

The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets.

Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity ("VIE").

In each case, NACCO

is not the primary beneficiary of the VIE as it does not exercise financial control;

therefore, NACCO does not consolidate the

results of these operations within its financial statements.

Instead, these contracts are accounted for as equity method

The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations

on the Consolidated Statements of Operations and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets.

The mines that meet the definition of a VIE are referred to collectively as the “Unconsolidated Subsidiaries.” For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S.

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

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

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

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.

Caddo Creek met the definition of a VIE prior to the cessation of mining on September 30, 2020.

The terms of the contract to perform mine reclamation contain a fixed-price component and therefore, Caddo Creek has been consolidated within the Company's financial statements since October 1, 2020.

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;

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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.

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 coal deliveries and earnings at MLMC.

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

Properties" on page 29 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

NAMining Segment

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

The segment is a primary platform for the Company’s growth and diversification of mining activities outside of the coal industry.

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

The segment is a platform for the Company’s growth and diversification of mining activities outside of the thermal coal industry.

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

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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, 2021, NAMining operates mines in Florida, Texas, Arkansas and Indiana and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

NAMining utilizes both fixed price and management fee contract structures.

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.

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 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.

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 overriding royalty interests, non-participating royalty interests or non-operated 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.

Total consideration for the 2021 and 2020 acquisitions of mineral and royalty interests was $5.3 million and $14.2 million, respectively.

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

The 2020 acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres.

Total mineral and royalty interests include approximately 127.8 thousand gross acres and 59.9 thousand net royalty acres at December 31, 2021.

The Company’s legacy royalty and mineral interests are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas),

Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas).

The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.

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

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

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

Royalty interests expire upon the expiration of the oil and gas lease.

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

Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.

• Mineral Interest.

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The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases.

The NPRI owner does;

however, typically receive royalty payments.

• Overriding Royalty Interest (“ORRIs”).

ORRIs are created by carving out the right to receive royalties from a working interest.

Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured.

Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability;

however, ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured.

ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

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The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired.

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

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

Total consideration for the 2022 and 2021 acquisitions of mineral and royalty interests was $11.9 million and $5.3 million, respectively.

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.

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.

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

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

The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.

Properties" on page 29 in this Form 10-K for discussion of the Company's proved reserves.

The principal customers of the Coal Mining segment are electric utilities, an independent power provider and a producer of activated carbon.

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

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

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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 royalty owner and non-operator, 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 2022 and 2021, 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.

In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE;

therefore, NACCO does not consolidate the results of these operations within its financial statements.

Instead, these contracts are accounted for as equity method investments.

For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE.

The loss of either of these contracts could have a material adverse effect on the Earnings of Unconsolidated Operations of the Coal Mining segment and a material adverse effect on the Company's Consolidated Statements of Operations.

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, 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.

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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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.

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

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.

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

There also continues to be an increase in the amount of electricity generated by wind and solar.

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

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

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

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

The significant increase in natural gas prices in 2021 compared to natural gas prices in 2020 contributed to an increase in customer power plant dispatch and coal deliveries in 2021.

Sustained higher natural gas prices could lead to increased demand for coal and positively affect 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.

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

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

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.

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.

Business — Government Regulation" on page 8 in this Form 10-K for further discussion.

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

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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.

In addition, because the Company has fewer financial resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.

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.

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.

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.

Human Capital

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Benefits offered to employees include:

• Medical, dental and vision benefits for employee, spouse and dependents;

• Medical, dental and vision benefits for employees, spouses and dependents;

• Flexible spending accounts for both healthcare and dependent care;

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

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

• Paid vacation and holidays;

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The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged.

The Company works to match employees with assignments that capitalize on the skills, talents and potential of each employee.

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

The Company believes in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability.

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

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

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

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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In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training.

Ethics are deeply embedded in the Company’s values and business processes.

The Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy require employees to comply with applicable laws and regulations, maintain high ethical standards and report situations of actual or potential noncompliance.

The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.

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Available Information

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available, free of charge, through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”).

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”).

The content of the Company's website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to the Company's website is intended to be an inactive textual reference only.

The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company and other issuers that file electronically with the SEC.

Under Rule 12b-2 of the Exchange Act, the Company qualifies as a “smaller reporting company” because its public float as of the last business day of the Company’s most recently completed second quarter was less than $250 million.

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

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.

Numerous governmental permits and approvals are required for coal mining operations.

The Company's subsidiaries hold or will hold the necessary permits at all of its coal mining operations except Demery and Caddo Creek, where the customers hold the respective permits.

The Company believes, based upon present information provided to it by these third-party mine permit holders, that these third parties have all permits necessary for the Company to operate or reclaim Caddo Creek and Demery;

however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.

The Company's subsidiaries hold or will hold the necessary permits at all of its lignite coal mining operations.

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.

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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.

Mine Health and Safety Laws

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

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

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

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.

Clean Air Act and Affordable Clean Energy Rule ("ACE")

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.

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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.

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.

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

In March 2021, EPA finalized the “Revised Cross-State Air Pollution Rule” to address the remand of the CSAPR update.

The final rule requires no further obligations in states where the Company’s customers operate a power plant.

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”).

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

SIPs will be 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.

See "Item 1A - “Risk Factors” on page 20 for further discussion of the regional haze program.

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.

The North Dakota Department of Environmental Quality (“NDDEQ”) finalized its state implementation plan and submitted it to the EPA for approval in August 2022.

The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at Coyote Station power plant.

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”).

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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.

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”.

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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.

T he 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.

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, the ACE rule limited "best system of emission reduction" ("BSER") to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU.

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 they vacated the ACE rule .

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 recently granted certiorari.

The Supreme Court of the United States will hear the case in February 2022.

Depending on the outcome of the Supreme Court ruling, the EPA may 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.

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 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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however, the United States rejoined in February 2021.

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

Signific ant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions.

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.

Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions.

Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock.

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

In December 2021, the EPA and COE released a draft “Step One” rule to redefine WOTUS by formally rescinding the NWPR and replacing it with a new definition.

If the new definition is promulgated as drafted, some of the Company's operations could incur additional costs to mitigate streams and wetlands.

Bellaire is treating mine water drainage from coal refuse piles associated with two former underground coal mines in Ohio and one former underground coal mine in Pennsylvania, and is treating mine water from a former underground coal mine in Pennsylvania.

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.

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.

See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

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

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

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

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

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.

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

This new rule 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.

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.

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.

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

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

If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

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

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

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 October 2021, the CEQ issued a new draft rule rescinding many of the revisions from 2020 update.

If finalized as drafted, the revised NEPA regulations could adversely affect the Company’s ability to secure necessary permits.

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.

Regulation of the Oil and Natural Gas Industry

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

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

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

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

transportation.

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

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The operations of the Company’s third-party lessees are subject to various types of regulation at the federal, state and local level.

These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations.

These types of regulation include requiring permits for the drilling of wells, drilling bonds and generating reports concerning operations.

The states, and some counties and municipalities, in which the Company has mineral interests also regulate one or more of the following:

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

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

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying 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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However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level.

In addition, the Biden administration has signaled the intent to stop hydraulic fracturing on federal land.

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

The Biden administration has also signaled the intent to stop hydraulic fracturing on federal land.

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

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

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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.

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

The listing of either of these species, or any others, in areas where the Company holds minerals interests could cause lessees to incur increased costs arising from species protection

measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

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

Natural Gas Sales and Transportation

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Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources.

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

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

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EXECUTIVE OFFICERS OF THE COMPANY

Name Age Current Position Other Positions

61 President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from prior to 2017) From prior to 2017 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO.

From prior to 2017 to September 2017, Assistant Secretary of Hamilton Beach Brands ("HBB") and Kitchen Collection ("KC").

Dilluvio 32 Associate Counsel and Assistant Secretary of NACCO and NACoal (from June 2019) From prior to 2017 to May 2019, Associate, Sidley Austin LLP (law firm).

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 46 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2017) From prior to 2017 to September 2017, Assistant Secretary of HBB and KC.

Haberer 55 Associate General Counsel of NACCO (from prior to 2017), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2017) and President, North American Coal Royalty Company (an NACoal subsidiary) (from prior to 2017)

Fry 46 Associate General Counsel and Assistant Secretary of NACCO (from May 2017), Associate General Counsel and Assistant Secretary of NACoal (from May 2017) From prior to 2017 to April 2017, Senior Counsel, Locke Lord (law firm).

Maxwell 44 Vice President - Financial Planning and Analysis and

Treasurer (from September 2017)

From prior to 2017 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.

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)

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name Age Current Position Other Positions

Anderson 46 President - Mitigation Resources (from March 2017) From prior to 2017 to February 2017, Environmental Manager, The Sabine Mining Company (an NACoal subsidiary).

Berry 54 President - NAMining (from prior to 2017)

Dale 47 Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017)

Dewing 65 Vice President - Operations of NACoal (from January 2017)

Hart 43 Controller of NACoal (from September 2019) From November 2017 to August 2019, Assistant Controller of NACoal.

From prior to 2017 to October 2017, Assistant Controller at Rowan Companies, plc.

Larson 38 President - Catapult Mineral Partners, LLC (from May 2019) and Director - Oil and Gas Development (from April 2019) From prior to 2017 to March 2019, Engineer at Pioneer Natural Resources.

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)

Patrick Sullivan, Jr.

1 unchanged sentence

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