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(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (440) 229-5151

Securities registered pursuant to Section 12(b) of the Act

Securities registered pursuant to Section 12(g) of the Act: Class B Common Stock, $1 par value per share. Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.           Yes ¨    No þ    

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.        Yes ¨    No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.                                         Yes þ     No £

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

 Yes þ     No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes ☐    No ☑

   

Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2023 (the last business day of the registrant's most recently completed second fiscal quarter): 156,415,693

Number of shares of Class A Common Stock outstanding at February 29, 2024: 5,929,944

Number of shares of Class B Common Stock outstanding at February 29, 2024: 1,565,685

Portions of the Company's Proxy Statement for its 2024 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.

 

NACCO Industries, Inc.® (“NACCO” or the “Company”) 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.

NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913.

NACCO’s portfolio of businesses operates under the umbrella of NACCO Natural Resources. Management continues to view the long-term business outlook for NACCO positively. The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses.

The Minerals Management segment, through the Company’s Catapult business unit, is focused on maximizing the value of existing mineral and royalty assets while it continues to pursue expansion of its asset base through acquisitions of additional mineral and royalty interests. The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that delivers near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the mid-teens as this business model matures. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development as these costs are borne entirely by third-party exploration and development companies that lease the minerals. The Company is also considering additional investment opportunities, including non-operating working interests, as it continues to pursue diversification of revenue streams.

NAMining continues to focus on profit improvement initiatives as well as growth through additional business development activities. NAMining is targeting potential customers who require a broad range of minerals and materials where it can leverage the Company’s core mining skills. The goal is to build NAMining into a leading provider of contract mining services for customers who produce a wide variety of minerals and materials. NAMining intends to be a substantial contributor to operating profit over time, including in its Sawtooth Mining subsidiary when production commences at Thacker Pass, which is targeting initial production in late 2026. Once production commences, Sawtooth Mining Company, LLC ("Sawtooth") will receive a management fee per metric ton of lithium delivered. The pace of achieving substantially improved results at NAMining will depend on the execution and successful implementation of profit improvement initiatives in the aggregates operations, and the mix and scale of new projects. A number of initiatives have already delivered improved financial results.

Mitigation Resources continues to develop its business, which creates and sells stream and wetland mitigation credits, provides services to those engaged in permittee-responsible mitigation and provides mine reclamation and other environmental restoration services. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. Mitigation Resources is making strong progress toward its goal of becoming a top ten provider of stream and wetland mitigation services in the southeastern United States. The Company believes that Mitigation Resources can provide solid rates of return on capital employed as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices, weather and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants. While the Company realizes the coal mining industry faces political and regulatory challenges and demand for coal is projected to decline over the longer-term, the Company believes coal should be an essential part of the energy mix in the United States for the foreseeable future.

The Company continues to look for ways to create additional value by utilizing its core mining competencies around reclamation and permitting through the development of utility-scale solar projects. Reclaimed mining properties offer large tracts of land that could be well-suited for solar and other energy-related projects. These projects could be developed by the Company itself or through joint ventures that include partners with expertise in energy development projects.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification is designed to generate cash that can be re-invested to strengthen and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.

On December 18, 2023, Mississippi Lignite Mining Company ("MLMC") received a force majeure event notice from its customer related to an issue that began on December 15, 2023 and impacted one of two boilers at the Red Hills Power Plant. The notice did not provide a timeline for resolution of the issue. As of March 6, 2024, the impacted boiler is still not operational. The prolonged mechanical issue is expected to result in a reduction in customer demand and will have a significant impact on the Company's results of operations during 2024. The Company determined the anticipated reduction in customer demand caused by this issue was an indicator of potential impairment. The Company reviewed MLMC's long-lived assets for impairment as of December 31, 2023 and determined the carrying amount of its long-lived assets were not recoverable. As a result, the Company recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis.

During 2023, Minerals Management, through Catapult, completed an acquisition of $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin. During 2022, Catapult acquired $11.4 million of mineral and royalty interests in the Texas portion of the Permian Basin and the Wyoming portion of the Powder River Basin as well as a small acquisition of mineral interests in the New Mexico portion of the Permian Basin.

The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant. On May 2, 2022, Great River Energy ("GRE") completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy became effective upon the closing of the transaction. Falkirk continues to supply all coal requirements of Coal Creek Station and is paid a management fee per ton of coal delivered. To support the transfer to new ownership, Falkirk agreed to a reduction in the current per ton management fee from the effective date of the CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with 2021 fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation. Rainbow Energy is responsible for funding all mine operating costs, including mine reclamation, and directly or indirectly providing all of the capital required to operate the mine. The initial production period is expected to run through May 1, 2032, but the CSA may be extended or terminated early under certain circumstances.

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

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. On December 1, 2022, HLCP Ethanol Holdco, LLC (“HLCP”) completed its acquisition of MAG. Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million during 2022.

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

During 2023, the Board of Directors of the Company approved the termination of the Combined Defined Benefit Plan for NACCO and its subsidiaries (the “Combined Plan”) and Combined Plan participants were offered lump-sum distributions as part of the termination process. As a result of the lump-sum distributions, the Company recognized a non-cash, pension settlement charge of $1.8 million. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.

In December 2023, the Company entered into a power purchase agreement with the Tennessee Valley Authority (“TVA”) for the energy generated from a proposed 67.5 MW solar photovoltaic electric generation facility to be developed on reclaimed land at the Company’s Red Hills Mine. The development of this project is subject to the favorable completion of an environmental impact study under the National Environmental Policy Act (“NEPA”) and approval of an interconnection agreement with TVA. In addition, the Company will enter into an engineering, procurement and construction agreement related to development of the project. The estimated commercial operation date for this generation facility is 2027.

The Coal Mining segment, operating as North American Coal, LLC, operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with its customer's operations.

As of December 31, 2023, the Coal Mining segment's operating coal mines were: The Coteau Properties Company (“Coteau”), Coyote Creek Mining Company, LLC (“Coyote Creek”), Falkirk and MLMC. Each of these mines supply lignite coal for power generation and delivers its coal production to an adjacent power plant or synfuels plant under a long-term supply contract. MLMC’s coal supply contract contains a take or pay provision but contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party; all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s financial statements. MLMC sells coal to its customer's Red Hills Power Plant at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC. The Red Hills Power Plant supplies electricity to TVA under a long-term power purchase agreement. MLMC’s contract with its customer runs through April 1, 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC. During 2023, MLMC completed mining in its original mine area and began mining in a new mine area. The move to the new mine area resulted in increased costs during 2023. MLMC does not anticipate opening additional mine areas through the remaining contract term unless doing so would result in improved economic returns.

On December 18, 2023, MLMC received a force majeure event notice from its customer related to an issue that began on December 15, 2023 and impacted one of two boilers at the Red Hills Power Plant. The notice did not provide a timeline for resolution of the issue. As of March 6, 2024, the impacted boiler is still not operational. The prolonged mechanical issue is expected to result in a reduction in customer demand and will have a significant impact on the Company's results of operations during 2024. The Company determined the anticipated reduction in customer demand caused by this issue was an indicator of potential impairment. The Company reviewed MLMC's long-lived assets for impairment as of December 31, 2023 and determined the carrying amount of its long-lived assets were not recoverable. As a result, the Company recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis.

measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to the Company. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

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

on the Consolidated Statements of Operations and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the “Unconsolidated Subsidiaries.” For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return; therefore, the Income tax provision line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

•Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but royalty interests may be calculated net of post-production expenses, and typically has no environmental liability. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.

•Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

•Non-Participating Royalty Interest (“NPRIs”). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases. The NPRI owner does; however, typically receive royalty payments.

•Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability; however, ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

Total consideration for the 2023 and 2022 acquisitions of mineral and royalty interests was $36.7 million and $11.9 million, respectively. The 2023 acquisition includes 43.4 thousand gross acres and 2.5 thousand net royalty acres. The 2022 acquisitions included 13.6 thousand gross acres and 880 net royalty acres. Total mineral and royalty interests include approximately 184.7 thousand gross acres and 63.3 thousand net royalty acres at December 31, 2023. Net royalty acres are calculated based on the Company’s ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

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

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

The principal customers of the NAMining segment are limestone producers and to a lesser extent, sand and gravel producers. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a mineral owner, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

In 2023 and 2022, two customers individually accounted for more than 10% of consolidated revenues. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenues for those years:

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

Coteau, Coyote Creek, Falkirk and MLMC each have only one customer for which they extract and deliver coal. The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems. All of the mines in the Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal being mined.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on pricing of renewable energy and the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions. The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and develop its reserves will depend upon the interaction of these factors.

Coal-fired electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal. Fluctuations in natural gas prices and the availability of renewable energy sources, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Over the longer term, the Company continues to believe that customer demand will remain pressured by regulations mandating or incentivizing the purchase of power from subsidized renewable energy sources, particularly wind and solar. See “Item 1. Business — Government Regulation" on page 8 in this Form 10-K for further discussion. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2023 based on total coal tons produced.

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

In the Minerals Management segment, the oil and gas industry is intensely competitive; the Company primarily competes with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than the Company’s financial resources permit. Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals Management segment’s ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price.

Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

The Company has experienced limited variability in its results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns.

The NAMining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions and pandemics, all of which can result in variations in demand for aggregates.

In the Minerals Management segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, geology, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of the Company's control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices during the first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations. Due to these seasonal fluctuations, Minerals Management results of operations for individual quarterly periods may not be indicative of the results that may be realize on an annual basis.

As of December 31, 2023, the Company and its subsidiaries had approximately 1,700 employees, including approximately 1,100 employees at the Company’s unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes it has good relations with its employees.

Market-Based Compensation: NACCO believes its employees are critical to its success and invests in its employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives. The Company offers a 100% 401(k) matching contribution up to 5% of compensation and a generous profit-sharing contribution for all of our full-time and part-time employees. The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. Benefits offered to employees include:

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

•Flexible spending accounts for both healthcare and dependent care;

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

•Paid vacation and holidays;

•Parental leave;

•Short-term and long-term disability benefits;

•Wellness incentives for employees;

•Life and AD&D insurance benefits;

•Charitable donation matches; and

•Employee assistance program.

Employee Development: The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments that capitalize on the skills, talents and potential of each employee, and provides opportunities for professional growth. The Company believes in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability.

Safety: Employee safety in the workplace is one of the Company’s core values. The Company is committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. The National Mining Association ranks NACCO as an industry leader in safety, and the Company's incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data. The Company has earned more than 100 safety awards at the state and national levels. NACCO strives to have zero safety incidents or injuries. The Company's operations have onsite safety personnel who train employees in safe work practices, review safety-related incidents and recommend improvements when appropriate. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company believes communication related to “near misses,” safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.

Company Ethics: The Company has processes in place for compliance with its Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of the Company's Directors and employees annually complete certifications with respect to compliance with the Company's Code of Corporate Conduct. In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training. The Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy require employees to comply with applicable laws and regulations, maintain high ethical standards and report situations of actual or potential noncompliance. The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.

Community Engagement: The Company supports its local communities and is committed to helping them remain safe, healthy and resilient. The Company's past activities include corporate donations, volunteerism and education. Community engagement is encouraged and supported through the Company's matching gift program. The Company will match employee contributions up to $5,000 per employee if program criteria are met.

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

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The content of the Company's website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to the Company's website is intended to be an inactive textual reference only. The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company and other issuers that file electronically with the SEC.

Under Rule 12b-2 of the Exchange Act, the Company qualifies as a “smaller reporting company” because its public float as of the last business day of the Company’s most recently completed second quarter was less than $250 million. For as long as the Company remains a “smaller reporting company,” it may take advantage of certain exemptions from the SEC’s reporting requirements that are otherwise applicable to public companies that are not smaller reporting companies.

The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment.

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

Some laws, as discussed below, place many requirements on the Company's operations and its customers' operations. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.

Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of the Company’s Minerals Management segment.

Mine Health and Safety Laws

The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.

Environmental Laws

The Company's coal mining operations are subject to various federal environmental laws, as amended, including:

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

•the Clean Air Act, including amendments to that act in 1990 (“CAA”);

•the Clean Water Act of 1972 (“CWA”);

•the Resource Conservation and Recovery Act ("RCRA");

•the National Environmental Policy Act of 1970 (“NEPA”); and

•the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").

In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations. Both federal and state inspectors regularly visit mines to enforce compliance. The Company has ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Coal Mining segment.

Surface Mining Control and Reclamation Act

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency. These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation. Although mining permits have stated expiration dates, SMCRA provides for a right of successive renewal. The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits.

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the “Fund”), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The 2021 Infrastructure Investment and Jobs Act reauthorized the Abandoned Mine Land fee at a reduced rate. The fee for lignite coal was reduced from $0.08 per ton to $0.064 per ton and for other surface-mined coal from $0.28 per ton to $0.224 per ton. These fees have been reauthorized until the end of fiscal year 2035.

SMCRA establishes operational, reclamation and closure standards for surface coal mines. The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit. While these obligations are largely unfunded, they can require securitization through bonding, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the “EPA”), the U.S. Army Corps of Engineers and the Office of Surface Mining Reclamation and Enforcement ("OSMRE") have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.

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

Greenhouse Gas (“GHG”) Emissions

In July 2019, the EPA finalized a rule that repealed the Clean Power Plan ("CPP") that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (“ACE”) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units (“EGUs”). In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit Court”) vacated the ACE rule, including its repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. On June 30, 2022, the Supreme Court of the United States (“SCOTUS”) issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its statutory authority when it adopted the CPP.

On May 11, 2023, the EPA published a draft rule imposing limits on GHG emissions from existing coal and new natural-gas electric generating units, which could compel such facilities to install additional pollution controls or shut down ("CPP2"). The proposed CPP2 includes guidelines for carbon dioxide ("CO2") emissions from existing EGUs with a proposed compliance

date of January 1, 2030. For coal-fired steam EGUs that plan to operate past January 1, 2040, the EPA is proposing a best

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

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

2040, the EPA is proposing a BSER of 40 percent natural gas co-firing on a heat input basis. Coal-fired steam EGUs that will permanently cease operations between December 31, 2031 and January 1, 2035, will be subject to an annual capacity factor

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

methods of operation and maintenance that maintain current emission rates. Each of the EGUs supplied by the Company would

be subject to these proposed requirements.

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

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

raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive, and/or result in early closure

which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these

plants, including closure of the Company's coal mines. Any such closure of the Company's mines could have a material adverse

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

Clean Air Act

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides ("NOx"), mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.

The CAA requires the EPA to review national ambient air quality standards (“NAAQS”) every five years to determine whether revisions to current standards are appropriate. In addition, states are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain NAAQS every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to affect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides ("SOx") without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour sulfur dioxide concentrations, averaged over 3 years. On January 6, 2023, the EPA proposed to lower the level of the particulate matter. If enacted as proposed, this rule would require fossil fuel generating units to install additional emission reducing technologies, which will ultimately increase the cost of fossil fuel generated energy or cause potential EGU retirements.

In 2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. While the CSAPR affects states in the eastern half of the U.S. and Texas, it does not affect EGUs in North Dakota. This rule imposes

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

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

In 2019, certain states submitted SIPs to the EPA in response to the 2015 ozone standard reduction. On February 13, 2023, the EPA rejected the SIPs. The EPA’s action to deny the SIPs was challenged in various courts, including the 5th Circuit Court of Appeals (the “Fifth Circuit”). The Fifth Circuit issued a stay of the SIP rejection in Texas, Louisiana, and Mississippi which prevents the federal implementation plan ("FIP") from going into effect pending the outcome of the litigation challenges.

On June 5, 2023, the EPA published the FIP in the Federal Register. The FIP decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stay beginning in 2024 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls.

On July 31, 2023, the EPA promulgated an interim rule (“Interim FIP”) that addresses the various judicial orders where the SIP rejection has been stayed. The Interim FIP requires these states to return to the previously approved NOx trading program and emission caps. The Interim FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the power plants in these states under the Group 2 trading program.

In December 2023, the SCOTUS agreed to hear a challenge to the FIP. The case was heard in February 2024 and will be decided later in the year. Should the FIP be fully implemented in states where a stay has been issued, the rule could influence the closure of some coal-fired EGUs that have not installed selective catalytic reduction technologies, potentially including the EGU supplied by MLMC. The Company cannot predict the outcome of the legal challenges to the: (i) various state challenges; (ii) the FIP promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders. If the original FIP withstands legal challenge, it would increase the cost of operating the customer facility serviced by MLMC.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA

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

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

On March 6, 2023, the EPA concluded that it is appropriate and necessary to regulate mercury-containing particulate matter. In April 2023, the EPA drafted proposed revisions to MATS. These revisions would remove the mercury emission limit for lignite-fired EGUs and require particulate emission reductions for all coal-fired EGUs. If enacted as proposed, this rule could influence the closure of additional coal-fired EGUs, potentially including all of the EGUs supplied by the Company.

The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period.

State implementation of the EPA’s Regional Haze Rule could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could result in the premature closure of the power plant and the Coyote Creek mine. The North Dakota Department of Environmental Quality (“NDDEQ”) finalized its state implementation plan and submitted it to the EPA for approval in August 2022. The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at Coyote Station power plant. Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be economically feasible for Coyote Creek's customers to invest in such equipment, which could result in early retirement of Coyote Station and the Coyote Creek mine.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “NSR program”). Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. Both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”.

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

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

requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of

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

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

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

could be materially adversely affected.

Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing GHG emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or States, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

The U.S. Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and “cap-and-trade” programs, and mandates or incentives to generate electricity by using renewable energy sources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions of GHGs. The U.S. has not ratified the emission targets of the Kyoto Protocol or any other GHG agreement. Though the U.S. has not accepted these international GHG limiting treaties, numerous lawsuits and regulatory actions have been undertaken by states and environmental groups to try to force controls on the emission of carbon dioxide; or to prevent the construction of new coal-fired power plants.

As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change (“Paris Agreement”). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories. Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets. The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. The United States is a party to the Paris Agreement. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a material adverse effect on the Company’s business, financial condition and results of operations.

Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.

The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.

Clean Water Act

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

discharge, including from coal mines. These federal and state requirements could require more costly water treatment and could

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

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

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

Corps of Engineers for operations in waters of the United States ("WOTUS.") The SCOTUS heard the Sackett vs. EPA case in October 2022, which considered whether certain wetlands constitute WOTUS. Prior to the SCOTUS issuing a decision, in January 2023, the EPA published a new rule that redefines WOTUS using an expansive significant nexus test. The new definition expanded the scope of federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands. The new WOTUS definition was ultimately stayed in 24 states, including Louisiana, Mississippi and North Dakota. On May 25, 2023, the SCOTUS issued its Sackett vs. EPA ruling that defines WOTUS as “a relatively permanent body of water connected to traditional interstate navigable waters” with a “continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.” The SCOTUS decision rejected the “significant nexus” test used by the EPA in its 2023 WOTUS rule.

As a result of the Sackett decision, the EPA and the Army Corps of Engineers authored a revised definition of WOTUS and promulgated a final rule that removed references to “significant nexus”. The new rule does not go into effect in states

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

the legal challenge to the rule will resume. In the meantime, securing CWA permits may be more challenging since the agencies

in the states where a stay has been issued have less guidance to rely on to determine whether certain features are considered

WOTUS.

Bellaire is treating mine water drainage from coal refuse piles associated with former underground coal mines in Ohio and Pennsylvania and is treating mine water from a former underground coal mine in Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. Bellaire was notified by the Pennsylvania Department of Environmental Protection during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.

Resource Conservation and Recovery Act

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

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

waste management. In 2020, the EPA finalized changes to the coal combustion residual ("CCR") rule that classified all clay-lined surface impoundments that receive CCR as unlined. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of disposal capacity with a deadline to initiate closure and a new site-specific alternative due to permanent cessation of coal-fired boilers with deadlines to complete closure. These rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of the Company's mines. Any such closure of the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

In compliance with these regulations, the owner of the Coal Creek Station power plant, Falkirk’s customer, submitted a CCR Part B application to the EPA in 2020 asserting a unit complied with the CCR rules. In the first quarter of 2023, the EPA proposed to deny the owner’s application. The owner and other parties have submitted additional information and comments supporting the owner’s position. If the EPA ultimately denies the owner’s application, a new liner may need to be installed or new waste management processes and/or units may need to be constructed. Accordingly, it is possible that a denial by the EPA could require a temporary unit shut down. Any temporary unit shut down could result in a temporary suspension of operations at Coal Creek Station. To minimize any impact to operations, Coal Creek Station is moving forward with plans to dry CCR materials produced by the plant, reducing the need to utilize the lined area in question. Falkirk is the sole supplier of lignite coal to Coal Creek Station. Any suspension of operations at Coal Creek Station would eliminate the need for lignite coal during the

suspension period. Any such suspension of operations at Coal Creek Station or any of the power plants supplied by the

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

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

exempt inactive CCR surface impoundments at inactive facilities (legacy CCR surface impoundments). If finalized as proposed,

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

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

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to OSMRE. OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by the EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

National Environmental Policy Act

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

assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger

these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required

information to the appropriate federal agency to enable it to complete the required study. Historically, this process has been

lengthy and may take several years to complete. In January 2023, the White House Council on Environmental Quality ("CEQ")

issued interim guidance that instructs federal agencies to quantify GHG emissions and use the social cost of greenhouse gases to calculate a monetary metric associated with the proposed actions’ climate effects. The NEPA and interim guidance could adversely affect the Company’s ability to secure necessary permits.

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

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

strategic plan for the agency. Additionally, the order requires agencies conducting NEPA reviews to assess direct, indirect and

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

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

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

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

collectively known as the Builder Act. The Builder Act includes amendments to NEPA which codify past regulatory reforms,

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

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

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

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

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar assets.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids ("NGLs") are not currently regulated and are made at market prices.

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the Company’s mineral interests, which could materially adversely affect the Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company’s mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

In December 2023, EPA finalized a rule that will require oil and gas producers to reduce methane and other air pollutants from existing sources. Oil and gas companies will be required to phase out routine flaring of natural gas and install methane leak detection equipment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

The operations of the Company’s third-party lessees are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and generating reports concerning operations. The states, and some counties and municipalities, in which the Company has mineral interests also regulate one or more of the following:

•the location of wells;

•the method of drilling and casing wells;

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

•the rates of production;

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

•the plugging and abandoning of wells; and

•notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of the Company’s mineral interests can produce from existing wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the Company’s mineral interests, negatively affect the economics of production from these wells or limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying the Company's mineral and royalty interests operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level. The Biden administration has also signaled the intent to stop hydraulic fracturing on federal land.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying the Company’s mineral interests to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying the Company’s mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying the Company’s mineral interests.

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of the Company’s properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests.

For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where the Company holds mineral interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase operators’ costs of transporting gas to point-of-sale locations.

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, the Company believes that the regulation of oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, the Company believes that access to oil pipeline transportation services generally will be available to its operators to the same extent as to the Company or its competitors.

States regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but the Company cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.

Comprehensive Environmental Response, Compensation and Liability Act

CERCLA and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

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

The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, the Company may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect the Company’s results of operations and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which the Company is required to conduct its operations.

Other Regulations

The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”). The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy sources, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels and impact demand for fossil fuels. The ultimate impact on fossil fuel demand and the Company is uncertain and may change as implementation of the Inflation Reduction Act moves forward. The subsidization of alternative energy sources may have a material adverse effect on the Company’s business, financial condition or results of operations.

The following tables set forth as of March 1, 2024 the name, age, current position and principal occupation and employment during the past five years of the Company’s executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.

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.

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 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 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.

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.

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 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.

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 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.

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.

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.

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.

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:

•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.

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.

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 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.

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.

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.

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.

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 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.

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 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.

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 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 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.

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 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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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 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.

None.

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 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.

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.

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.

Table 1.1 Production Summary

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

2.1 Red 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.

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

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.

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.

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.

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

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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:

Location

Mining Method

Total Historical Cost of Mine Property, Plant and Equipment (excluding Coal Land, Real Estate and Construction in Progress), Net of Applicable Accumulated Amortization, Depreciation and Impairment

Unconsolidated Mining Operations

(in millions)

Freedom Mine — The Coteau Properties Company

Dragline operation with 3 draglines

$

116.2

Falkirk Mine — The Falkirk Mining Company

Dragline operation with 4 draglines

$

58.4

Coyote Creek Mine — Coyote Creek Mining Company, LLC

Dragline operation with 1 dragline

$

114.6

Consolidated Mining Operations

Red Hills Mine — Mississippi Lignite Mining Company

Dragline operation with 1 dragline

$

52.8

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:

(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.

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.

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 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.

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

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.

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:

(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.

(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.

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.

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.

(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.

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.

(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.

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.

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.

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.

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.

(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.

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.

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.

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 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.

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

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

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.

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

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.

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 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 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 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.

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

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.

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

NACCO's consolidated capital structure is presented below:

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.

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.

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.

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.

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:

(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.

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

The following table identifies the components of change in operating profit for 2023 compared with 2022:

Operating (loss) profit changed unfavorably by $109.7 million in 2023 compared with 2022. The change in operating profit was primarily due to:

•A long-lived asset impairment charge;

•A decrease in gross profit;

•The non-recurrence of $14.0 million recognized in 2022 related to the contract termination settlement with GRE; and

•A decrease in the earnings of unconsolidated operations.

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. The Company determined the anticipated reduction in customer demand caused by this issue was an indicator of potential impairment. The Company recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023. The $65.9 million relates exclusively to MLMC; however, $60.8 million and $5.1 million were recorded on the Coal Mining segment and the Minerals Management segment, respectively, as certain MLMC land assets were recorded within the Minerals Management segment. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge.

The decrease in gross profit was primarily due to an increase in the cost per ton delivered at MLMC. The increase in cost per

ton delivered at MLMC is due to costs associated with establishing operations in a new mine area and a reduction in the number of tons severed. The reduction in severed tons was due to adverse mining conditions during 2023, as well as operational inefficiencies related to final mining activities at the existing mine area. Fewer tons severed caused a decrease in tons held in inventory since more tons were delivered than produced during 2023. This resulted in an increase in the cost per ton sold and $7.5 million of inventory impairment charges to write down coal inventory to its net realizable value.

The decrease in the earnings of unconsolidated operations was primarily due to a reduction in customer requirements at Coteau and Falkirk. A reduction in the per ton management fee at Falkirk, effective May 2022 through May 2024, to support the transition of the Coal Creek Station Power Plant to Rainbow Energy also contributed to the 2023 decrease in earnings.

Aggregate tons delivered by the NAMining segment were as follows for the years ended December 31:

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

(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.

Total revenues increased 5.7% in 2023 compared with 2022 primarily due to:

•An increase in reimbursable costs at Sawtooth, which have an offsetting amount in cost of sales and have no impact on operating profit;

•An increase in customer requirements and tons delivered at the consolidated quarries; and

•Higher dragline part sales.

These improvements were partially offset by a reduction in mine reclamation revenue at Caddo Creek.

The following table identifies the components of change in operating profit for 2023 compared with 2022.

Operating profit increased $1.1 million in 2023 compared with 2022 primarily due to the absence of a voluntary retirement program charge, as well as increases in the earnings of unconsolidated operations and gross profit.

During 2022, the Company implemented a voluntary retirement program for employees who met certain age and service requirements to reduce overall headcount. As a result of this program, operating profit in 2022 included a charge of $0.8 million related to one-time termination benefits.

The increases in the earnings of the unconsolidated operations and gross profit were primarily due to higher earnings at the limestone quarries. An increase in dragline part sales and higher earnings at Sawtooth also contributed to the increase in gross profit. These improvements were largely offset by the absence of earnings associated with Caddo Creek reclamation activities.

The results of operations for the Minerals Management segment were as follows for the years ended December 31:

During 2023, the oil and natural gas industry experienced a decline in commodity prices compared with 2022. Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below demonstrates such volatility with the average price as reported by the United States Energy Information Administration for the twelve months ended December 31: