NC US Equity☆

Item 1A. RISK FACTORS

The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect the Company’s business.

Risks related to the Coal Mining segment

Termination of or default under long-term mining contracts could adversely affect the Company's business, financial condition, results of operation and cash flows.

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure could have a material adverse effect on the Company’s business, financial condition and results of operations.

The coal mining industry is subject to ongoing complex governmental regulations and legislation that could adversely impact the Company’s long-term mining contracts and the Company’s results of operations, liquidity, financial condition and cash flow.

The United States Environmental Protection Agency (the “EPA”) has a comprehensive regulatory program to manage the disposal of coal combustion residuals (“CCR”) from coal-fired power plants as non-hazardous material under the Resource Conservation and Recovery Act (“RCRA”). Individual states administer some or all of the RCRA provisions. The North Dakota Department of Environmental Quality approved Falkirk’s customer's plan for an alternate disposal liner to store coal ash at the Coal Creek Station power plant. In the first quarter of 2023, the EPA proposed to deny the application. If denied, a new liner or new waste management unit(s) may need to be installed, which could result in the temporary suspension of operations at Coal

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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.

The EPA also has a comprehensive regulatory program to manage airborne emissions from coal-fired power plants. During 2023, the EPA proposed updated rules related to mercury and greenhouse gas emissions from coal-fired power plants. The first update was to the Mercury Air Toxics Standard, or MATS. In this update, the EPA proposed to eliminate a mercury emission standard for lignite-fired power plants that currently permits higher mercury emissions by lignite plants than other coal plants. In the event this rule is adopted as proposed, and not successfully legally challenged, it could result in the closure of many lignite-fired power plants, potentially including all of those supplied by the Company. The second update was the EPA’s proposed new rule for greenhouse gas emissions from coal-fired power plants. In this proposed new rule, the EPA requires that power plant owners that intend to operate the plants beyond 2031 utilize controls, including reduced levels of power generation, co-firing coal and natural gas and installing carbon capture and sequestration to reduce greenhouse gas emissions. Each of these controls may impact the plant owners’ profitability and could result in the closure of coal-fired power plants, potentially including all of those supplied by the Company. The closure of any of the power plants supplied by the Company could have a material adverse effect on the Company’s business, financial condition and results of operation.

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. The Company is required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability.

See “Item 1. Business — Government Regulation" on page 8 in this Form 10-K for discussion of regulations that could materially adversely affect the Coal Mining segment.

The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect the Company's business, financial condition, results of operation and cash flows.

Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of the Company's control. Future environmental regulation of GHG emissions, CCRs and/or new federal and state mandates for increased use of electricity derived from renewable energy sources could accelerate the use by utilities of fuels other than coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could accelerate the realignment of customers' power generation portfolios to reduce the electric power generated from coal.

If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See “Item 1. Business — Business Developments" on page 2 in this Form 10-K for further discussion.

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MLMC is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal-fired generation, changes in customer demand and inflationary adjustments.

The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability.

Similar to the Company's unconsolidated mines, all production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce its inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.

Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. Diesel fuel is heavily weighted among the indices used to determine the coal sales price. The diesel fuel-related component of the coal sales price is based on average price changes over time whereas the impact on actual costs from changes in diesel fuel prices is more immediate; therefore, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

Any reduction in customer demand at MLMC, including, but not limited to, reduced mechanical availability of the customer’s power plant, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Red Hills Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.

The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a "management fee" approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the Unconsolidated Subsidiaries' customers pay the Company its agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, fluctuations in demand due to unanticipated weather conditions, scheduled and unscheduled outages at the Coal Mining segment's customers' facilities, unplanned equipment failures including U.S. power grid reliability issues, economic conditions or governmental regulations or comparable policies which may promote dispatch of power generated by renewable energy sources, such as wind or solar, and the realignment of customers' power generation portfolios that reduce the electric power generated from coal could have a material adverse effect on the Company's results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce the Company's profitability.

Changes in coal consumption patterns of U.S. electric power generators could adversely affect the Company's profitability.

The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.

Changes in the utility industry that affect NACCO's customers could also adversely affect the Company. The increased availability of renewable energy sources has contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to continue to displace a significant amount of coal-fired electric power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources

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have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.

Changes in federal and state mandates that would include an acceleration in the use of electricity derived from renewable energy sources could result in a decrease in coal consumption by the electric power generation industry and the Company’s customers.

Any of these risks could result in a decrease in coal consumption by the Company’s customers and could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.

Federal and state statutes require the Company to restore mine property in accordance with specified standards and an approved reclamation plan, and require that the Company obtain and periodically renew permits for mining operations. Regulations require the Company to incur the cost of reclaiming current mine disturbance at operations where the Company holds the mining permit. Estimates of the Company's total reclamation and mine closing liabilities are based upon permit requirements and the Company's engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on the Company’s business and could significantly reduce its profitability.

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

Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.

Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.

Many conditions beyond the Company's control can decrease the delivery, and therefore the use, of coal to the Company's customers. These conditions include weather, pandemics, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, any of which could significantly reduce the Company's profitability.

The Company faces numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Information concerning the Company's mining operations in "Item 2 - Properties" on page 31 has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal at MLMC are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals, new mining or other data received.

There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond the Company's control. While the Company believes that its mineral reserve and resource estimates are developed using well-established practices and with appropriate controls, mineral reserve and mineral resource estimation is an imprecise and subjective process. Estimates of mineral reserves and resources depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

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•Geologic and mining conditions, including the Company's ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;

•Demand for the Company's minerals;

•Contractual arrangements, operating costs and capital expenditures;

•Development and reclamation costs;

•Mining technology and processing improvements;

•The effects of regulation by governmental agencies;

•The ability to obtain, maintain and renew all required permits;

•Employee health and safety; and

•NACCO's ability to convert all or any part of mineral resources to economically extractable mineral reserves.

As a result, actual tonnage recovered, estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect the Company’s actual reserves and resources. Any material inaccuracy in estimates related to the Company's reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect the Company business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC’s property disclosure requirements for mining companies.

A defect in title or the loss of a leasehold interest in certain property could limit the Company's ability to mine coal reserves or result in significant unanticipated costs.

The Company conducts a significant part of its coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. The Company may not verify title to leased properties or associated coal reserves until the Company has committed to developing those properties or coal reserves. The Company may not commit to develop property or coal reserves until the Company has obtained necessary permits and completed exploration. As such, the title to property that the Company intends to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, some leases require the Company to produce a minimum quantity of coal and/or pay minimum production royalties. The Company's inability to satisfy those requirements may cause the leasehold interest to terminate.

Risks related to the NAMining segment

The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.

The Company has expanded its overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as the Company scales the NAMining business. As NACCO continues to grow the NAMining business, the Company must effectively integrate, develop and motivate new employees, as well as existing employees who are promoted or moved into new roles, while maintaining the effectiveness of its business execution. In part, NAMining’s success depends on its ability to integrate new customers in an efficient and effective manner. The Company anticipates that it will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If the Company is unable to manage this growth and the associated expenses effectively, the Company may not be able to take advantage of market opportunities or remain competitive. The Company may also fail to execute on its business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.

NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.

NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that its existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.

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The Company is subject to risks involved in the development of new mining projects.

From time to time, the Company seeks to develop new mining projects, including the Thacker Pass project. The risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays or reductions in making capital expenditures by NAMining's customers, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on the Company’s business, financial condition and results of operations.

NAMining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.

As of December 31, 2023, over 75% of the quarries NAMining operates are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for NAMining’s services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the NAMining business.

Risks related to the Minerals Management segment

The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.

The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company primarily derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company’s mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where the Company owns mineral and royalty interests, the Company’s lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments may give the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

Minerals are a depleting asset. Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company’s reserves and royalty income will decline.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless the Company’s third-party lessees conduct successful ongoing well development activities or the Company continually acquires mineral and royalty interests, production and income related to the Company’s mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators’ success in developing the Company’s current and future mineral and royalty interests. These operators may not have access to the capital needed to develop the Company's mineral interests. The Company may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve the Company uses to project future royalty income is subject to numerous assumptions and limitations. Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to

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factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

Substantially all of the Minerals Management segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying the Company’s interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company’s control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

The Minerals Management segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Company's control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including the ongoing conflict between Israel and Hamas, the conflict between Russia and Ukraine and associated oil and natural gas import bans as well as U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

The marketability of oil and natural gas production is dependent upon transportation, pipelines and refining facilities and continued operation of the U.S. power grid. Any limitation in the availability of these items could interfere with our third-party lessee’s ability to market oil and natural gas production and may adversely affect the Minerals Management segment’s financial condition or results of operations.

The marketability of our third-party lessee’s production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties as well as continued reliable operation of the U.S power grid. Any significant disruption in the U.S. power grid, gathering system or transportation, processing, or refining-facility capacity could reduce our third-party lessee’s ability to market oil production and may adversely affect the Minerals Management segment’s financial condition or results of operations.

Risks related to corporate structure

The amount and frequency of dividend payments made on NACCO's common stock could change.

The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions and other factors the Board of Directors may consider. Accordingly, holders of NACCO's common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.

The price of NACCO's securities may be volatile.

The price of the Company's common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in the Company's quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism; (v) announcements concerning NACCO, its customers or its competitors; (vi) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (vii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of the Company's common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in the Company's common stock may not be able to resell their stock at or above the price they paid or at all. Further, NACCO could

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be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on the Company's operating results.

NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in the Company's certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire the Company, even if doing so might be beneficial to NACCO's stockholders. Provisions of the Company's by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of NACCO's common stock and may have the effect of delaying or preventing a change in control.

The Company’s stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.

The Company’s Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.

Repurchases under the stock repurchase program could affect the price of the Company's Class A common stock. The existence of a stock repurchase program could cause the price of the Company's Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for the Company’s Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of the Company’s Class A common stock may decline below the levels at which the Company repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program’s effectiveness. Furthermore, the stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares of the Company's Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of the Company's Class A common stock to decline.

NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.

The Company is currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare the Company's performance with other public companies.

NACCO cannot predict whether investors will find the Company's common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for the Company's common stock and the stock price may be more volatile.

Certain members of the Company's extended founding family own a substantial amount of its Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.

The Company has two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2023, accounted for approximately 27 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2023, accounted for the remaining voting power of the Company. As of December 31, 2023, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 99 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 81 percent of the Company's total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent

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other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.

General Risk Factors

The Company’s effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.

The Company is subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in the Company’s effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.

Current and future capital and credit market conditions could adversely affect the Company’s ability to obtain bank financing on reasonable terms.Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in the Company’s ability to maintain financing at current levels.

The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. The Company’s wholly-owned subsidiary has a revolving line of credit of up to $150.0 million that expires in November 2025. The Company’s ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or refinance with terms that are as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's operating results and financial condition.

Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.

Federal and state laws require the Company to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation and black lung benefit costs, leases, transmission interconnection construction costs, power purchase agreement delivery obligations and other obligations. Future federal and state laws and regulations, regional transmission organizations and power purchase agreement customers may require higher amounts of financial security, including as a result of changes to certain factors used to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As the Company is required by state and federal law to have bonds or other acceptable security in place before mining can commence or for certain projects to move forward, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the Company's financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand other forms of collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on the Company’s liquidity and financial position. If the Company is unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase the Company’s costs and likely require greater use of alternative sources of funding for this purpose, which would reduce the Company’s liquidity.

Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in the Company’s ability to maintain insurance coverage at current levels.

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The Company holds a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because the Company is involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure the Company in the future. In addition, if the Company makes significant insurance claims under the Company’s insurance policies, such claims may have a material adverse effect on its ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of its liability insurance coverage limits, could have a material adverse effect on the Company's operating results and financial condition.

Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on the Company or expose the Company to new or additional risks.

Expectations relating to environmental, social and governance (“ESG”) matters have been rapidly evolving and increasing. Government organizations, including the SEC, are enhancing or advancing legal, regulatory and disclosure requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. The Company could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce the Company’s carbon footprint and promote sustainability. Investors may request the Company implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, the Company may face reputational challenges in the event its ESG practices are inconsistent with the third-party views of acceptable ESG practices. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

The Company may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

The Company’s business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.

Like many other companies, the Company is the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers.

As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat the Company's or a third-party service provider's security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications the Company may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.

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A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of the Company's business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and the Company's reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.

The Company relies on information technology systems to operate its business and to record and process transactions; respond to customer inquiries; purchase supplies; provide services; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite the Company's efforts, the Company’s information technology systems may be vulnerable, from time to time, to damage or interruption from user error, computer viruses, power outages, third-party intrusions and other technical malfunctions.

Through the Company’s business operations, the Company collects and stores confidential information from its customers and vendors and personal information and other confidential information from its employees. Although the Company has taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate the Company’s or its vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact the Company’s ability to respond appropriately.

The Company could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt the Company’s operations, damage the Company’s reputation, and expose the Company to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on the Company’s business, financial condition and results of operations.

Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support the Company's activities could impact the business. The Company is continuously installing new and upgrading existing information technology systems. The Company uses employee awareness training around phishing, malware, and other cyber risks. The Company believes these incidents are likely to continue and is unable to predict the direct or indirect impact of future attacks or breaches to business operations.

The Company’s operations could be disrupted by natural or human causes beyond its control.

The Company’s operations are subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment. While all of the Company’s operations are located in the United States, the Company participates in a global supply chain, and if governments regulate or restrict the flow of labor or products or impede the travel of Company personnel, the Company’s ability to conduct normal business operations could be impacted which could adversely affect the Company’s results of operations and liquidity.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 1C. CYBERSECURITY

The Company maintains a cybersecurity program that is aligned with its business and has established policies and processes for assessing, identifying, and managing material risk from cybersecurity threats, which have been integrated into its overall risk management processes and governance structure.

The Company has implemented and invested in, and will continue to implement and invest in, controls, technologies, and resources (both internal and external) that are designed to identify, protect against, detect, respond to and mitigate cybersecurity risks, in alignment with frameworks established by the National Institute of Standards and Technology. These include, but are not limited to, internal reporting mechanisms, monitoring and detection tools, threat intelligence, and general and role-based training. The Company also maintains third party management processes to identify and manage the cybersecurity risks

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associated with third party service providers. The Company periodically evaluates its cybersecurity program internally and by engaging with consultants to conduct reviews and assessments of the program. Such reviews and assessments may include penetration testing, maturity assessments as well as table-top and other exercises with subsequent remediation of key findings. Additionally, the Company has a Cybersecurity Task Force in place that is comprised of individuals across various departments within the organization including information systems, legal, finance, human resources and internal audit which meets regularly to further advance the Company’s cybersecurity strategy.

The Board of Directors (the “Board”) oversees NACCO's risk management. The full Board regularly reviews information provided by management to oversee risk identification, risk management and risk mitigation strategies. The Audit Review Committee assists the Board with cybersecurity risk oversight. The Audit Review Committee is responsible for regularly reviewing and discussing with management risk exposure relating to cybersecurity, which includes reviewing the state of the Company's cybersecurity program and emerging cybersecurity developments and threats, as well as the steps management has taken to monitor and mitigate such exposure. In 2023, the Board and the Audit Review Committee received periodic updates throughout the year on cybersecurity matters and these updates are part of their standing agendas.

The Company’s Chief Information Security Officer ("CISO") leads the Company’s cybersecurity program and is responsible for the management of its cybersecurity risks. The CISO has extensive cybersecurity knowledge and skills gained from over 30 years of technical and business experience, including as General Manager & President of MLMC, Vice President of Mississippi Operations and Vice President of Innovation & Technology. The CISO holds a bachelor’s degree in engineering, an executive MBA, and certifications in cybersecurity from Harvard. Additionally, the CISO is currently enrolled in an Executive course through Northwestern’s Kellogg School of Management focused on artificial intelligence (“AI”). The CISO reports directly to the President and Chief Executive Officer. The CISO manages a team of internal and external resources that have expertise and experience in cybersecurity. The CISO is informed of cybersecurity incidents by the cybersecurity team, which is generally responsible for monitoring the prevention, detection, mitigation, and remediation of cybersecurity incidents. The Company has an established process governing its assessment, response and internal and external notifications upon the occurrence of a cybersecurity incident, including evaluation of the potential impacts of cybersecurity incidents to determine materiality. Depending on the nature and severity of an incident, this process provides for escalation procedures upon discovery of material cybersecurity risks, including notification to the Company’s executive management and/or Board.

As of the date of this filing, the Company’s business strategy, results of operations, and financial condition have not been materially impacted as a result of any previously identified cybersecurity incidents; however, we cannot provide assurance that they will not be materially impacted in the future by such risks or any future material incidents. For additional information regarding the Company’s cybersecurity risks, please refer to "Item 1A - “Risk Factors” on page 19.

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Item 2. PROPERTIES

Coal Mining Segment - Operations

NACCO-owned Properties

1.0 INTRODUCTION

Information concerning the Company’s mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. As used in this Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. Readers are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the subpart 1300 of Regulation S-K.

Readers are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, readers are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category. Likewise, readers are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See "Item 1A - “Risk Factors” on page 19.

The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summary (“TRS”) prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. The TRS was prepared by employees of the Company. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, incorporated herein by reference and made a part of this Report on Form 10-K. The information regarding MLMC was reviewed by employees of the Company that are qualified persons as defined by subpart 1300 of Regulation S-K.

Coteau, Falkirk, Coyote Creek and MLMC, each wholly-owned subsidiaries of NACCO, operate surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model.

Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During 2023 Subject to SEC Section 1300 Reporting.

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Figure 1.1 Surface Coal Mines Operational During 2023 Subject to SEC Section 1300 Reporting

A summary of coal production at the Mines subject to SEC Section 1300 Reporting for the past three years has been tabulated and is presented on Table 1.1 Production Summary.

Tons (in millions)

The Falkirk Mining Company 7.9 7.6 6.6

Coyote Creek Mining Company 2.0 1.8 2.2

Mississippi Lignite Mining Company 3.0 3.2 2.7

Table 1.1 Production Summary

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

2.1Red Hills Mine — Mississippi Lignite Mining Company

MLMC is the owner and operator of the Red Hills Mine. The Red Hills Mine is a lignite surface mine in production. Prior to MLMC, there were no previous mining operations on the Red Hills Mine property.

The MLMC contract is the only operating coal contract in which 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.

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A summary of coal production at MLMC for the past three years has been tabulated and is presented on Table 2.1 Production Summary.

Tons (in millions)

Mississippi Lignite Mining Company 3.0 3.2 2.7

Table 2.1 Production Summary

The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant. 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 Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi (Figure 2.1). The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 8,026 acres of surface interest and 5,015 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,490 acres of coal interests and the right to utilize approximately 4,956 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,663 acres of coal interest. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations. The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.

The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Choctaw Water Association. Fuel for equipment is supplied by Dickerson Petroleum located in Kosciusko. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations.

Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.

Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.

The Red Hills Mine is in close proximity to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.

In addition to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman, and is accessible by Highway 9 and Highway 15. MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 1, 2032. No mineral processing occurs at the Red Hills Mine.

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The geology encountered at the Red Hills Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Red Hills Mine.

Development of the Red Hills Mine began in 1997, with full commercial deliveries commencing in 2002. The mining operation is comprised of four major equipment fleets. Primary removal of burden is achieved with one 82-cubic yard electric-powered dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The mine office facilities and original equipment fleets at the Red Hills Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2023 is $52.8 million.

The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One notice of violation ("NOV") was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. A second NOV was issued in June 2022 for a water sampling violation.Both NOVs were not related to the mining permit. Permitting requirements are discussed in Section 17.0 of the TRS.

Figure 2.1 – Red Hills Mine Location

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Mineral Resources and Reserves have been summarized from the December 31, 2022 TRS for MLMC and have been modified from mining depletion. The Mineral Resources and Mineral Reserves as of December 31, 2023 are included as Table 2.2 and Table 2.3. Coal qualities are reported on an as-received moisture basis. Based on the December 31, 2022 TRS, prices in Table 2.2 are based on economic cut-off grades of $29.66 per ton at MLMC and prices in Table 2.3 are based on economic cut-off grades of $36.06 per ton at MLMC.

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed TRS for the Mississippi Lignite Mining Company – Red Hills Mine dated December 31, 2022.

Section 11.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Resources. Assumptions include a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $29.66 per ton. A further description of the verified drilling data used to model the lignite deposit for estimation of Mineral Resources is provided in Section 7.2 Drilling Exploration, 8.0 Sample Preparation, Analyses, and Security, and Section 9.0 Data Verification.

Section 12.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Reserves, and include the following:

•Maximum stripping ratio: 14:1;

•Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;

•Mining costs on a unit basis remain relatively consistent with historical performance;

•Minimum minable lignite thickness: 1.0 feet;

•Minimum parting thickness before seams are composited: 6.0 inches;

•Maximum depth of mining: approximately 320 feet;

•Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft3; and

•Recovery rates by seam ranging from 67% to 100%.

Modifying factors including dilution parameters and technical information related to the mining process are described in detail under Section 13.0 Mining Methods. Economic factors to support the Mineral Reserve estimates are described in Section 18.0 Capital and Operating Costs and 19.0 Economic Analyses.

The Mineral Resources as of December 31, 2023 presented in Table 2.2 below have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources reported herein are exclusive of Mineral Reserves.

Lignite Coal Resource Classification Tonnage(Kiloton "Kt") Grades/Qualities

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

Note:

–Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral Resources will be converted into Mineral Reserves.

–Mineral Resources are in-situ and exclusive of 22.5 million tons (Mt) of Mineral Reserves.

–Mineral Resources are reported using an economic cutoff of $29.66 per ton.

–Resources are presented with a minimum 1 foot seam thickness, a maximum as received moisture basis ash content of 30%, and a minimum calorific value of 4000 BTUs on an as received moisture basis cutoff.

–Resources are estimated using Vulcan Software.

–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

Table 2.2 Mineral Resources Summary as of December 31, 2023

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The Mineral Reserves as of December 31, 2023 presented in Table 2.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

Lignite Coal Reserve Classification Tonnage(Kt) Grades/Qualities

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

Note:

–Mineral Reserves have been demonstrated to be economic based on a positive cash flow

–Mineral Reserves are stated on a Run of Mine basis

–An economic cutoff in the Life of Mine plan averaged $36.06 per ton and was used to demonstrate coal reserves

–Recovery varies by coal seam and ranges from 67% to 100%

–Mineral Reserves use an economic cut-off of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.

–Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.

–Mineral Reserves are estimated using Vulcan Software.

–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the Qualified person ("QP"). Summation errors due to rounding may exist.

Table 2.3 Mineral Reserves Summary as of December 31, 2023

Table 2.4 describes the difference between the Mineral Reserves and Mineral Resources reported as of December 31, 2022 and December 31, 2023.

Table 2.4. Net difference of reported Mineral Resources and Mineral Reserves from previous reporting period to current reporting period.

The Mineral Resources and Mineral Reserves as of December 31, 2023 reflect modifications from mining extraction of Mineral Reserves. No updates to Mineral Resources were made for 2023. Mineral Reserves have been exhausted in Mine Area 1 and mining extraction is occurring in Mine Area 3. Additionally, MLMC delivered 2.9 million tons during 2023.

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2.2 Material Properties with no Mineral Resources or Mineral Reserves

The lignite coal tonnages at Coteau, Falkirk and Coyote Creek have not been classified as “measured resources”, “indicated resources”, or “inferred resources” as defined in Items 1300 through 1305 of Regulation S-K, and as a result, do not have any “proven” or “probable” reserves under such definition and are therefore classified as an “Exploration Stage Property” pursuant to Items 1300 through 1305 of Regulation S-K. Coteau, Falkirk and Coyote Creek will continue to be classified as exploration stage properties until such time as proven or probable mineral reserves have been established in accordance with subpart 1300 of Regulation S-K, even though they continue to deliver lignite to their respective customers.

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. inflation. The customers are responsible for funding all mine operating cost, including final mine reclamation, and directly or indirectly providing 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.

Coteau, Coyote Creek and Falkirk each have only one customer for which they extract and deliver coal. These customers operate coal-fired electric generation power plants adjacent to each mine location (and in the case of Coteau, a synthetic natural gas and chemical/fertilizer production facility).

The sales price under the Coteau, Coyote Creek and Falkirk contracts are not market driven. Unlike traditional sales made based on market factors, under the provisions of the long-term mining agreements, the coal sales price at Coteau, Coyote Creek and Falkirk includes (i) all costs incurred to extract, process and deliver coal (i.e. the cost of production) and (ii) the agreed-upon profit per ton of coal or MMBtu unit delivered to the customer. Cost of production includes all the costs actually incurred in the operation of the mine including mining, processing and delivery of coal. Costs included within revenue include all production, transportation and maintenance costs including, without limitation, the following types of costs:

◦Labor, which include wages and all related payroll taxes, benefits and fringes, including welfare plans; group insurance, vacations and other comparable benefits of employees

◦Materials and supplies,

◦Tools,

◦Machinery and equipment not capitalized or leased,

◦Costs of acquiring interests in coal reserves and surface lands,

◦Rental of machinery and equipment,

◦Power costs,

◦Reasonable and necessary services by third parties

◦Insurance including worker’s compensation

◦Certain taxes, and

◦Cost of reclamation

The contractually-determined coal sales price includes reimbursement of all costs incurred and the agreed-upon profit. The agreed-upon profit adjusts based on changes in the level of established indices (e.g., CPI-U and/or PPI indices). The cost-plus nature of the contracts provide assurance that all costs incurred, including contemporaneous and final reclamation, will be reimbursed by the respective customer and negates any risk of loss which allows the mines to remain cash flow positive through the end of the contract terms. The coal sales price as well as profitability at Coteau, Falkirk and Coyote Creek are not subject to any change based on market factors. Profitability at these mines is affected by two factors: demand for coal (because this impacts units of agreed profit that are charged) and changes in the indices that determine coal sales price (because this adjusts the agreed-upon per unit profit). Under any scenario, Coteau, Coyote Creek and Falkirk will be cash flow positive as a result of the terms of the mining agreements.

Extraction of Coteau, Coyote Creek and Falkirk’s lignite tonnages is only economically viable as a result of the long-term mining agreements in place with each mine’s respective customer. The development of the Coteau, Coyote Creek and Falkirk mines was conducted in tandem with the development of the respective mine mouth power plants each serve. The power plants were designed to operate exclusively on the coal provided by the adjacent mines. No other market exists for the lignite at Coteau, Coyote Creek and Falkirk as the cost of transportation makes sales to any entity other than the current mine-mouth operator unprofitable.

Coteau, Coyote Creek and Falkirk 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

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

Coteau

The Freedom Mine, operated by Coteau, generally produces between 12.5 million and 13.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. Although the term of the existing lignite sales agreement terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of Coteau.

The Freedom Mine is located approximately 90 miles northwest of Bismarck, North Dakota (Figure 2.2). The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 368 leases granting the right to extract approximately 33,676 acres of coal interests and the right to utilize approximately 23,451 acres of surface interests. In addition, Coteau owns in fee 33,888 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.

Figure 2.2 – Freedom Mine Location

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also come from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations.

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The main entrance to the Freedom Mine is accessed by traveling north of Beulah on Highway 49 for one mile, then north on County Road 21 for two miles, then west on County Road 26 for three miles, and then north on County Road 15 for two miles as shown on Figure 2.2. Location of the Freedom Mine.

Travel to the Freedom Mine by air is possible by means of the Bismarck Municipal Airport, Bismarck, ND, which is approximately 90 miles southeast of the mine. From the airport, the mine is accessed by means of ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 28 miles on ND Highway 49 to Beulah, ND, and so on as explained in the previous paragraph.

Travel to the Freedom Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

The coal tonnages are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coteau for the purpose of refining guidance related to ongoing operations. It is common practice at the Freedom Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Coteau utilizes standard surface mining techniques to extract coal from the proposed permit area. Mining operations will typically occur in a sequence of seven events: suitable plant growth material removal, overburden removal, coal removal, overburden replacement, final grading, suitable plant growth material replacement, and revegetation.

The mine office facilities and original equipment fleets at the Freedom Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coteau evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2023 is $116.2 million.

The Freedom Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Freedom Mine in the past three years. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045 will be acquired as needed. No mineral processing occurs at the Freedom Mine.

Falkirk Mine

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually. The mine started delivering coal in 1978 primarily for the Coal Creek Station, an electric power generating station. Coal Creek Station was owned by GRE until May 1, 2022 when it was purchased by Rainbow Energy. The initial production period is expected to run through May 1, 2032, but the coal sales agreement may be extended or terminated early under certain circumstances. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.

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The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83 (Figure 2.3). Falkirk holds 338 leases granting the right to extract approximately 43,648 acres of coal interests and the right to utilize approximately 23,844 acres of surface interests. In addition, Falkirk owns in fee 40,826 acres of surface interests and 1,788 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

The towns of Underwood and Washburn are located within ten miles of the mine, with other small communities also nearby. Numerous employees also reside in Bismarck and Mandan, a distance of about 50 miles.

The Falkirk Mine receives both its power and water from Coal Creek Station. However, Falkirk’s East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by multiple local vendors including: Farstad Oil, Missouri Valley Petroleum, and Enerbase Cooperative Resources.

The main entrance to the Falkirk Mine is accessed by traveling north from Bismarck on State Highway 83 for approximately 50 miles, then going west on the access road, 1st Street SW located four miles south of Underwood. The mine office is located two miles to the west.

Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via US Highway 83.

The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.

The coal tonnages are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coal occurs in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

Operationally, overburden and interburden removal are accomplished using scrapers, dozers, front end loaders, truck shovel fleets, and draglines. Lignite is mined with front end loaders or hydraulic backhoes, and loaded into haul trucks to transport to the stockpile or directly to the customer via truck dumps and conveyors.

Fill-in drilling programs are routinely conducted by Falkirk for the purpose of refining guidance related to ongoing operations. It is common practice at the Falkirk Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 1320-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The mine office facilities and original equipment fleets at the Falkirk Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Falkirk evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2023 is $58.4 million.

The Falkirk Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Falkirk Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. No mineral processing occurs at the Falkirk Mine.

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Figure 2.3 – Falkirk Mine Location

Coyote Creek

The Coyote Creek Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 2016 to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. The term of the existing lignite sales agreement terminates in 2040.

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota (Figure 2.4). The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

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Figure 2.4 – Coyote Creek Mine Location

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply and employment base. A vast supply and employment base also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and Montana-Dakota Utilities Co., and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations.

The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 1.0 Location of Coyote Creek Mine.

Travel to the Coyote Creek Mine by air is possible using the Bismarck Municipal Airport, Bismarck, ND, approximately 75 miles southeast of the mine. From the airport, the mine is accessed using ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 21 miles on ND Highway 49 to County Road 25, then west for four miles on County Road 25.

Travel to the Coyote Creek Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

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The coal tonnages are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coyote Creek for the purpose of refining guidance related to ongoing operations. It is common practice at the Coyote Creek Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Operationally, overburden removal is accomplished using scrapers, dozers, front end loaders, excavators, truck fleets, and a dragline. Lignite is mined with front end loaders, and loaded into haul trucks to transport to the coal stockpile.

The mine office facilities and original equipment fleets at the Coyote Creek Mine were constructed, acquired, or purchased during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coyote Creek evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2023 is $114.6 million.

The Coyote Creek Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Coyote Creek Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. No mineral processing occurs at the Coyote Creek Mine.

3.0 Internal Control Disclosure Over Mineral Resources and Reserves

The modeling and analysis of the Company’s resources and reserves has been developed by Company mine personnel and reviewed by several levels of internal management, including the QPs. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QPs and Company staff. This section summarizes the internal control considerations for the Company’s development of estimations, including assumptions, used in resource and reserve analysis and modeling.

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QPs and Company management agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QPs.

Estimations and assumptions were developed independently for each significant mineral location. All estimates require a combination of historical data and key assumptions and parameters. When possible, resources and data from generally accepted industry sources were used to develop these estimations. Review teams were created by utilizing subject matter experts from across all of NACCO to review the cost assumptions and estimations used as the basis of the classification of mineral resources and reserves.

Geological modeling and mine planning efforts serve as a base assumption for resource estimates at MLMC. These outputs have been prepared and reviewed by Company personnel. Mine planning decisions are determined and agreed upon by Company management. Management adjusts forward-looking models by reference to historic mining results, including by reviewing actual versus predicted levels of production from the mineral deposit, and if necessary, re-evaluating mining methodologies if production outcomes were not realized as predicted. Ongoing mining of the mineral deposit, coupled with product quality validation pursuant to Company and customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the deposit. Geologic modeling assumptions are evaluated to historic mining

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results and are adjusted if necessary to better reflect actual mining results. Ongoing quality validation of production also provides a means to monitor for any potential changes in quality. Also, ongoing monitoring of ground conditions within the mine, surveying for evidence of subsidence and other visible signs of deterioration that may signal the need to re-evaluate rock mechanics and structure of the mine ultimately inform extraction ratios and mine design, which underpin mineral reserve estimates.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, changes in QPs, identifying hazards and informing operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

4.0 Customer-owned Properties

South Hallsville No. 1 Mine — The Sabine Mining Company

The Sabine Mining Company (“Sabine”) operated 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 in the first quarter of 2023 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. During the third quarter of 2023, Sabine and SWEPCO entered into an agreement under which Sabine will provide mine reclamation services through September 30, 2026. On October 1, 2026, SWEPCO will take over and complete the remaining mine reclamation services by acquiring all of the capital stock of Sabine.

5.0 Facilities and Equipment

The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2023 is set forth in the chart below:

Unconsolidated Mining Operations (in millions)

Consolidated Mining Operations

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NAMining Segment - Operations

NAMining provides contract mining services for independently owned mines and quarries, primarily operating and maintaining draglines at limestone quarries and utilizing other mining equipment at sand and gravel quarries. At December 31, 2023, NAMining operated 30 draglines and other equipment at 23 quarries. Of the 30 draglines, 7 are owned by the Company and 23 are owned by customers. At December 31, 2023, NAMining had $75.8 million in property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment.

The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer. The following mines were operational during 2023:

Location Name Aggregate Location State Customer Year NACCO Started Operations

White Rock — North Limestone Miami FL WRQ 1995

Krome Limestone Miami FL Cemex 2003

Alico Limestone Ft. Myers FL Cemex 2004

FEC Limestone Miami FL Cemex 2005

SCL Limestone Miami FL Cemex 2006

Central State Aggregates Limestone Zephyrhills FL McDonald Group 2016

Mid Coast Aggregates Limestone Sumter County FL McDonald Group 2016

West Florida Aggregates Limestone Hernando County FL McDonald Group 2016

St. Catherine Limestone Sumter County FL Cemex 2016

Center Hill Limestone Sumter County FL Cemex 2016

Inglis Limestone Crystal River FL Cemex 2016

Titan Corkscrew Limestone Ft. Myers FL Titan America 2017

Palm Beach Aggregates Limestone Loxahatchee FL Palm Beach Aggregates 2017

Perry Limestone Lamont FL Martin Marietta 2018

SDI Aggregates Limestone Florida City FL Blue Water Industries 2018

Newberry Limestone Alachua County FL Argos USA, LLC 2019

Seven Diamonds Limestone Pasco County FL Seven Diamonds, LLC 2021

Johnson County (a) Sand and gravel Johnson County IN Martin Marietta 2021

Little River Sand and gravel Ashdown AR Lehigh Hanson 2021

Rosser Sand and gravel Ennis TX Lehigh Hanson 2021

Brooksville Cement Plant Limestone Brooksville FL Cemex 2021

Ash Grove Limestone Louisville NE Ash Grove 2022

(a) The Johnson County quarry was idled during 2023. NAMining mined de minimis amounts at this location during the 2023 and 2022 periods.

NAMining's customers control all of the limestone and sand reserves within their respective mines. NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.

Access to the White Rock mine is by means of a paved road from 122nd Avenue.

Access to the Krome mine is by means of a paved road from Krome Avenue.

Access to the Alico mine is by means of a paved road from Alico Road.

Access to the FEC mine is by means of a paved road from NW 118th Avenue.

Access to the SCL mine is by means of a paved road from NW 137th Avenue.

Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.

Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.

Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.

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Access to the St. Catherine mine is by means of a paved road from County Road 673.

Access to the Center Hill mine is by means of a paved road from West Kings Highway.

Access to the Inglis mine is by means of a paved road from Highway 19 South.

Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.

Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.

Access to the Perry mine is by means of paved road from Nutall Rise Road.

Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.

Access to the Queenfield Mine is by means of paved road from Dabney's Mill Road (SR 604).

Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).

Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.

Access to the Little River mine is by means of an unpaved road from Little River 60.

Access to the Rosser mine is by means of a paved road from TX-34 S.

Access to Brooksville Cement plant is by means of a paved road from Cement Plant Road.

Access to Ash Grove Louisville Quarry is by means of a paved road from HWY 50.

Minerals Management - Operations

As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. Consequently, the exact number of wells producing from or drilling on the Company’s mineral interests at a given point in time is not determinable. The following table sets forth the Company’s estimate of the number of gross and net productive wells:

Gross Net Gross Net

Gross wells are the total wells in which an interest is owned.

Net wells are calculated based on the Company's net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.

The majority of the Company’s producing mineral and royalty interest acreage now, or in the future, can be pooled with third-party acreage to form pooled units. Pooling proportionately reduces the Company’s royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which the Company has such reduced royalty interest.

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The following table includes the Company's estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs:

Gross Acres Net Royalty Acres Gross Acres Net Royalty Acres

The Company may own more than one type of interest in the same tract of land, but the overlap is not significant. Net royalty acres are calculated based on the Company’s ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

The following table includes the Company's estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs:

Undeveloped acres are either unleased and open or are leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Production and Price History

The following table sets forth the estimated oil and natural gas production data related to the Company’s mineral and royalty interests as well as certain price and cost information for the years ended December 31:

Production data:

Average realized prices:

Average unit cost

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) BOE. Barrel of Oil Equivalent, a conversion factor of 6 MCF of gas was used for 1 equivalent bbl of oil.

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(4) As an owner of mineral and royalty interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. As a result, the Company estimated the last two months of 2023 and 2022 production and pricing data using projections based on decline rates of wells and prior expense information.

Evaluation and Review of Reserves

The reserve estimates as of December 31, 2023 were prepared by Haas Petroleum Engineering Services, Inc. ("Haas Engineering"). Haas Engineering has provided reservoir engineering services, consulting and ongoing support for major and independent petroleum companies, public utilities, financial institutions, investors, and government agencies since 1980. Haas Engineering does not own an interest in NACCO or any of the Company's properties, nor is it employed on a contingent basis. A copy of Haas Engineering's estimated proved reserve report as of December 31, 2023 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.

The properties evaluated for proved reserves are located in Alabama, Louisiana, New Mexico, Ohio, Pennsylvania, Texas and Wyoming and represent all of the Company’s oil and gas reserves. A reserves audit is not the same as a financial audit. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs.

The reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate reserves in conformance with SEC regulations. The maximum remaining reserves life assigned to wells included in this report is 50 years.

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to the Company's interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of the Company’s reserves is a function of:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

•future prices of oil, natural gas and NGLs, which may vary considerably from those estimated; and

•the judgment of the persons preparing the estimates.

The following table presents the Company's estimated net proved oil and natural gas reserves based on the reserve report prepared by Haas Engineering, the Company’s independent petroleum engineering firm. All of the Company’s reserves are located in the United States.

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Net reserves as of December 31, 2023 Net reserves as of December 31, 2022

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Internal Control Disclosure

The Company's internal staff works closely with Haas Engineering to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to NACCO's assets. Internal technical team members met with independent reserve engineers periodically during the period covered by the reserves report to discuss the assumptions and methods used in the proved reserve estimation process.

The preparation of the Company's proved reserve estimates is completed in accordance with internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•Review and verification of historical production data, which data is based on actual production as reported by third-party producers who lease the Company’s royalty and mineral interests;

•Preparation of reserve estimates by Haas Engineering under the direct supervision of internal staff;

•Verification of property ownership by the Company's land department; and

•No employee’s compensation is tied to the amount of reserves booked.

The Minerals Management Segment’s Vice President of Engineering and Finance is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas Engineering in the preparation of the third-party reserve report. The Vice President of Engineering and Finance has over 15 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests.

Estimated Proved Reserves

The following table summarizes changes in proved reserves during the year ended December 31, 2023:

Estimated Proved Reserves

Oil (bbl) (1) NGL (bbl) (1) Residue gas (Mcf) (2)

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Estimated Proved Undeveloped Reserves ("PUDs")

The following table summarizes changes in PUDs during the year ended December 31, 2023:

Estimated Proved Undeveloped Reserves

Oil (bbl) (1) NGL (bbl) (1) Residue gas (Mcf) (2)

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

As an owner of mineral and royalty interests, the Company generally does not have evidence or approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2023, PUD reserves consists of 45 wells in various stages of drilling or completions. As of December 31, 2023, less than 1% of the Company's total proved reserves were classified as PUDs.

Headquarter locations

NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.

Coal Mining and Minerals Management lease corporate headquarters office space in Plano, Texas.

NAMining leases office and warehouse space in Medley, Florida.

Item 3. LEGAL PROCEEDINGS

Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

Item 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.

At December 31, 2023, there were 660 Class A common stockholders of record and 113 Class B common stockholders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Issuer Purchases of Equity Securities (1)

(1) On November 7, 2023, the Company's Board of Directors approved a stock purchase program providing for the purchase of up to $20.0 million of the Company’s outstanding Class A common stock through December 31, 2025. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

Item 6. [RESERVED]

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

OVERVIEW

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."

Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (“NACCO” or the “Company”). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources® businesses. The Company operates under three business segments: Coal Mining, North American Mining® ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

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. underground mining activities.

All financial statement line items below operating loss/profit (other income, including interest expense and interest income, the benefit/provision for income taxes and net loss/income) are presented and discussed within this Form 10-K on a consolidated basis.

See “Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.

The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.

Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers." See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's revenue recognition.

Long-lived assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

that the carrying value of the long-lived asset or asset group exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. A reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, could adversely affect the Company's operating results. The costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC could materially reduce the Company's profitability. The Company determined that indicators of impairment existed at MLMC during the fourth quarter of 2023 and, as a result, MLMC's long-lived assets were reviewed for impairment. The Company assessed the recoverability of the MLMC asset group and determined that the assets were not fully recoverable when compared to the remaining future undiscounted cash flows from these assets. As a result, the Company estimated the fair value of the asset group which resulted in 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 discussion of the Company's impairment analysis.

Income taxes: The Company files income tax returns in the U.S. federal jurisdiction, and in various state and foreign jurisdictions. Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.

The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.

Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position. Since 2021, the Company has participated in a voluntary program with the IRS called Compliance Assurance Process (“CAP”). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

CONSOLIDATED FINANCIAL SUMMARY

The results of operations for NACCO were as follows for the years ended December 31:

Revenues:

Operating (loss) profit:

(Gain) loss on equity securities (1,958) 283

Other contract termination settlements — (16,882)

(Loss) income before income tax (benefit) provision (64,158) 87,723

Effective income tax rate 38.3 % 15.5 %

The components of the change in revenues and operating profit are discussed below in "Segment Results."

Other income, net

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 on the line "Other, net" within the accompanying Consolidated Statements of Operations. The $1.8 million charge represents a pro rata portion of the unrecognized net loss recorded in Accumulated other comprehensive loss. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.

During 2022, GRE 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. As a result, the Company recognized $16.9 million on the "Other contract termination settlements" line within the accompanying Consolidated Statements of Operations.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. Subsequent to the receipt of the additional membership units, the Company began to account for the investment under the equity method of accounting. During the third quarter of 2022, the Company recorded $2.2 million, which represented its share of MAG's earnings on the "Other, net" line within the accompanying Consolidated Statements of Operations.

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 and recognized a $1.3 million loss during the fourth quarter of 2022 on the line "Other, net" within the accompanying Consolidated Statements of Operations.

The Company received additional cash payments totaling $3.6 million during 2023 in connection with MAG's post-closing purchase price adjustment and the release of amounts held in escrow. The Company recognized the $3.6 million gain on the line "Other, net" within the accompanying Consolidated Statements of Operations.

Interest income increased $4.6 million primarily due to higher interest rates and a higher average invested cash balance during 2023 compared with 2022.

(Gain) loss on equity securities represents changes in the market price of invested assets reported at fair value. The change during 2023 compared with 2022 was due to fluctuations in the market prices of the exchange-traded equity securities. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's invested assets reported at fair value.

Income Taxes

Income tax benefit of $24.6 million for the year ended December 31, 2023 includes $4.0 million of discrete tax benefits, primarily the reversal of uncertain tax positionsand the impact of U.S. federal provision to return adjustments. Excluding the $4.0 million of discrete tax benefits, the effective income tax rate in 2023 was 32.0%.

Income tax expense of $13.6 million for the year ended December 31, 2022 included $1.5 million of discrete tax benefits, primarily from the reversal of uncertain tax positions as a result of the conclusion of the IRS examination of the Company’s 2013, 2014, 2015 and 2016 federal income tax returns. Excluding the $1.5 million of discrete tax benefits, the effective income tax rate in 2022 was 17.1%.

The change in the effective income tax rate for 2023 compared to 2022, excluding the impact of the long-lived asset impairment charge and discrete items, is primarily due to a decrease in earnings at entities that qualify for percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following tables detail the change in cash flow for the years ended December 31:

Operating activities:

Inventory impairment charge 7,514 — 7,514

Other contract termination settlements — (15,552) 15,552

Investing activities:

Proceeds from the sale of private company equity units 3,574 18,628 (15,054)

Equity method investment (3,464) — (3,464)

The $13.2 million change in net cash provided by operating activities during 2023 compared with 2022 was primarily due to a decrease in cash provided by net income adjusted for non-cash items, partially offset by a favorable change in cash provided by working capital. The Company’s non-cash items primarily include Long-lived asset impairment charge, Other contract termination settlements, Inventory impairment charge, Deferred income taxes, Depreciation, depletion and amortization, Stock-based compensation, and Loss (gain) on sale of assets.

The favorable change in working capital was mainly the result of a decrease in Trade accounts receivable during 2023 compared with a significant increase during 2022. In addition, a significant reduction in the Federal income tax receivable during 2023 compared with an increase during 2022 also contributed to the favorable change in working capital.

Financing activities:

Purchase of treasury shares (3,103) — (3,103)

Net cash provided by (used for) financing activities $ 1,468 $ (9,840) $ 11,308

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The change in net cash provided by (used for) financing activities was primarily due to debt borrowing during 2023 compared with debt repayments during 2022, partially offset by share repurchases during 2023. On November 7, 2023, the Company's Board of Directors approved a stock purchase program providing for the purchase of up to $20.0 million of the Company’s outstanding Class A common stock through December 31, 2025. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

Financing Activities

Financing arrangements are obtained and maintained at the subsidiary level. The Company has a secured revolving line of credit of up to $150.0 million (the “Facility”) that expires in November 2025. Borrowings outstanding under the Facility were $10.0 million at December 31, 2023. At December 31, 2023, the excess availability under the Facility was $105.1 million, which reflects a reduction for outstanding letters of credit of $34.9 million.

NACCO has not guaranteed any borrowings of its subsidiaries. Dividends (to the extent permitted by the Facility) and management fees paid by NACCO subsidiaries are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders.

The Facility has performance-based pricing, which sets interest rates based upon achieving various levels of debt to EBITDA ratios, as defined in the Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2023, for base rate and Secured Overnight Financing Rate loans were 1.23% and 2.23%, respectively. The Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.34% on the unused commitment at December 31, 2023. During the year ended December 31, 2023, the average borrowing under the Facility was $6.2 million. The weighted-average annual interest rate, including the floating rate margin, was 6.06% and 2.54% at December 31, 2023 and December 31, 2022, respectively.

The Facility contains restrictive covenants, which require, among other things, maintaining a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the Facility, of $15.0 million. At December 31, 2023, the Company was in compliance with all financial covenants in the Facility.

The obligations under the Facility are guaranteed by certain direct and indirect, existing and future domestic subsidiaries, and is secured by certain assets and the guarantors, subject to customary exceptions and limitations.

The Company believes funds available from cash on hand, the Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the Facility in November 2025.

See Note 8 and Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's other financing arrangements and leases, respectively.

Expenditures for property, plant and equipment and mineral interests

Following is a table which summarizes actual and planned expenditures (in millions):

Planned Actual Actual

Planned expenditures for 2024 are expected to be approximately $32 million in the NAMining segment, $20 million in the Minerals Management segment, $13 million in the Coal Mining segment and $4 million in Unallocated Items.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Expenditures are expected to be funded from internally generated funds and/or bank borrowings.

Capital Structure

NACCO's consolidated capital structure is presented below:

December 31

Debt to total capitalization 9 % 4 % 5 %

The $20.9 million increase in other net tangible assets was primarily due to a favorable change in Deferred income taxes.

During the fourth quarter of 2023, intangible assets, net, decreased by $22.0 million, primarily because the Company recorded a non-cash, long-lived asset impairment charge. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's impairment analysis.

Contractual Obligations, Contingent Liabilities and Commitments

Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company’s decisions to contribute above the minimum regulatory funding requirements. The Company does not expect to contribute to its pension plan in 2024 and any settlements will be paid out of pension plan assets. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.4 million per year from 2024 through 2033. Benefit payments beyond that time cannot currently be estimated. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2024 through 2033. Benefit payments beyond that time cannot currently be estimated.

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

NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

The Company is a party to certain guarantees related to Coyote Creek. The Company believes that the likelihood of future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.

The Company utilizes letters of credit to support commitments made in the ordinary course of business. As of December 31, 2023 and 2022, outstanding letters of credit totaled $34.9 million and $33.7 million, respectively.

ENVIRONMENTAL MATTERS

The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company’s policies stress environmental responsibility and compliance with these regulations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.

Certain states have enacted, and others are considering enacting, mandatory clean energy standards requiring utilities to meet certain thresholds of renewable energy sources and/or carbon-free energy supply. The current presidential administration has made climate change a focus, including consideration for legislation on clean energy standards and GHG emission, and the Company expects that to continue. The Company believes the move to require utilities to generate a greater portion of energy from renewable energy sources could create imbalances in the existing electric grid if fossil-fuel power plants are retired faster than renewable energy sources are developed resulting in electrical grid disruptions and outages. The Company will continue to monitor the progress of these initiatives and assess the potential impacts they may have on its financial condition, results of operations and disclosures.

SEGMENT RESULTS

COAL MINING SEGMENT

FINANCIAL REVIEW

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:

The results of operations for the Coal Mining segment were as follows for the years ended December 31:

Earnings of unconsolidated operations(a) 44,633 52,535

Contract termination settlement — 14,000

Amortization of intangible assets 2,998 3,719

Gain on sale of assets (339) (8)

(a) See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

2023 Compared with 2022

Revenues decreased 10.3% in 2023 compared with 2022 primarily due to a reduction in customer requirements at MLMC.

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