NACCO INDUSTRIES INC 10-K

Item 1. BUSINESS General 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. The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities. NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913. Business Strategy NACCO’s portfolio of businesses operates under the umbrella of NACCO Natural Resources. NACCO continues to focus on the execution of its two key strategies – Protect the Core and Grow and Diversify. Management continues to be optimistic about the long-term outlook in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification. The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. NAMining remains committed to expanding its business while improving operating efficiencies and scalability. NAMining continues to work with Lithium Americas to develop the Thacker Pass Project in northern Nevada, one of the largest lithium projects in the United States. The Company believes NAMining can grow to be a substantial contributor to operating profit over time, but the pace of growth will be dependent on the mix and scale of new projects and the successful implementation of projects to return NAMining to profitability. The Minerals Management segment continues to pursue acquisitions of mineral and royalty interests in the United States. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a proven business model and a strong network to source and secure new acquisitions. The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as development costs are borne entirely by third-party producers who lease the minerals. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development. Mitigation Resources creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation and environmental restoration. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. During 2022, Mitigation Resources purchased property near Dallas-Fort Worth, Texas and near Nashville, Tennessee to establish new mitigation banks. In addition, it established a joint venture to provide mitigation services for the Lake Ralph Hall reservoir project in North Texas. As of December 31, 2022, Mitigation Resources is involved in over 10 mitigation banks and permittee-responsible mitigation projects in Tennessee, Alabama, Mississippi and Texas. With additional projects in its pipeline for 2023, Mitigation Resources is making strong progress toward its goal to be a top ten provider of stream and wetland mitigation services in the southeastern United States. The Company believes that Mitigation Resources can provide solid rates of return as this business matures. The Company continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. 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 1 Table of Contents the Company's Coal Mining segment, since fuel cost is a significant driver for power plant dispatch. An increase in power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants. The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship. Business Developments Mississippi Lignite Mining Company ("MLMC") is the exclusive supplier of lignite to the Red Hills Power Plant in Ackerman, Mississippi. Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If lease payments are not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. On October 27, 2022, Southern Company disclosed in its Form 10-Q that it provided notice to the lessee, CGLP, to terminate the related operating and maintenance agreement effective June 30, 2023. CGLP failed to make the semi-annual lease payment due December 15, 2022. As a result, the Southern Company subsidiary was unable to make its corresponding payment to the debtholders. The parties to the lease agreement are currently negotiating a potential restructuring, which could result in rescission of the termination notice. The parties to the lease have entered into a forbearance agreement which suspends the related contractual rights of the parties while they continue restructuring negotiations. The ultimate outcome of this matter cannot be determined at this time but could have a material impact on the Company's financial statements if the operating and maintenance agreement is terminated. The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant. Coal Creek Station was previously owned by Great River Energy (“GRE”). On May 2, 2022, GRE completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. As a result of the completion of the sale of Coal Creek Station, the Coal Sales Agreement, the Mortgage and Security Agreement and the Option Agreement between GRE and Falkirk were terminated. 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 $30.9 million in the second quarter of 2022 as GRE paid NACoal $14.0 million in cash, transferred ownership of an office building with an estimated fair value of $4.1 million, and conveyed membership units in Midwest AgEnergy Group, LLC (“MAG”), a North Dakota-based ethanol business, with an estimated fair value of $12.8 million, as agreed to under the termination and release of claims agreement between Falkirk and GRE. Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. On December 1, 2022, HLCP Ethanol Holdco, LLC (“HLCP”) completed its acquisition of MAG. Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million. The Sabine Mining Company (“Sabine”) operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W. Pirkey Plant (the “Pirkey Plant”). SWEPCO is an American Electric Power (“AEP”) company. AEP intends to retire the Pirkey Plant during March 2023. Sabine expects deliveries to cease in March 2023 and final reclamation to begin on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine will receive compensation for providing mine reclamation services. In 2022, Minerals Management, through its Catapult business, completed two acquisitions. It acquired $11.4 million of mineral 2 Table of Contents and royalty interests in the Texas portion of the Permian Basin and the Wyoming portion of the Powder River Basin. It also completed a small acquisition of mineral interests in the New Mexico portion of the Permian Basin. Operations Coal Mining Segment The Coal Mining segment, operating as The North American Coal Corporation ® ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Lignite coal is surface mined in North Dakota, Texas and Mississippi. Each mine is fully integrated with its customer's operations and is the exclusive supplier of coal to its customer's facilities. During 2022, the Coal Mining segment's operating coal mines were: The Coteau Properties Company (“Coteau”), Coyote Creek Mining Company, LLC (“Coyote Creek”), Falkirk, MLMC and Sabine. Each of these mines supply lignite coal for power generation and delivers its coal production to an adjacent power plant or synfuels plant under a long-term supply contract. MLMC’s coal supply contract contains a take or pay provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings. At Coteau, Coyote Creek, Falkirk and Sabine, 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 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 NACCO and NACoal. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees. Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity ("VIE"). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method 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. While Falkirk meets the definition of a VIE, the completion of the Rainbow Energy transaction resulted in a VIE reconsideration event. As the terms of the CSA between Falkirk and Rainbow Energy are substantially the same as the terms of the coal supply contract between Falkirk and GRE, Falkirk remains a VIE and Rainbow Energy is the primary beneficiary; therefore, NACCO will continue to account for Falkirk under the equity method. The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred. The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC. MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC’s contract with its 3 Table of Contents customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC. See “Item 2. Properties" on page 29 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves. NAMining Segment The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for the Company’s growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2022, NAMining operates mines in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada. Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries. Minerals Management Segment The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals. The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests and overriding royalty interests. • 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. 4 Table of Contents The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract. The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development. Total consideration for the 2022 and 2021 acquisitions of mineral and royalty interests was $11.9 million and $5.3 million, respectively. The 2022 acquisitions included 13.6 thousand gross acres and 880 net royalty acres. The 2021 acquisitions included 20.6 thousand gross acres and 1.8 thousand net royalty acres. Total mineral and royalty interests included approximately 141.4 thousand gross acres and 60.8 thousand net royalty acres at December 31, 2022. The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) existing producing wells further along the decline curve that will generate stable cash flow. In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian basin and a secondary focus on other diversifying basins to increase regional exposure. While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in ORRIs, NPRIs or non-operated working interests under certain circumstances. The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator. The Company also manages legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations. See “Item 2. Properties" on page 29 in this Form 10-K for discussion of the Company's proved reserves. Customers 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 2022 and 2021, 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: Percentage of Consolidated Revenues Segment 2022 2021 Coal Mining customer 39 % 43 % NAMining customer 17 % 19 % 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. Competition Coteau, Coyote Creek, Falkirk, MLMC and Sabine each have only one customer for which they extract and deliver coal. The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include 5 Table of Contents 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 renewable pricing and the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions. The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and develop its reserves will depend upon the interaction of these factors. Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal. Fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Sustained higher natural gas prices could lead to increased demand for coal and positively affect the Coal Mining segment results. Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind and solar. 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 2022 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. Seasonality 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 6 Table of Contents production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure. Human Capital As of December 31, 2022, the Company and its subsidiaries had approximately 1,600 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 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. 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. 7 Table of Contents Available Information The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available 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. Government Regulation 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 coal mining operations and the limestone quarries where the Company provides services. 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. 8 Table of Contents 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; however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000. The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. 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. These obligations are largely unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage. 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. Clean Air Act The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The 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. States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. 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 9 Table of Contents published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides ("SOx") without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years. In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In March 2022, the EPA announced a federal plan to “help states fully resolve their Clean Air Act ‘good neighbor’ obligations for the 2015 ozone NAAQS. This new plan would double the number of covered states and require daily limits on emissions from large coal-fired power plants. The plan would also broaden the existing nitrogen oxides power plant trading program from 12 states to 25 during the summertime ozone season while also ratcheting down nitrogen oxides caps for states, starting in 2023. If this plan is finalized as proposed, it could have a material adverse effect on the Company’s business, financial condition or results of operations. The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market. 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. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits. In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019. While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021. Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized. SIPs have been sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and Wildlife Service and the United States Forest Service and all corresponding public comment periods. State implementation of the EPA’s Regional Haze Rule could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could result in the premature closure of the power plant and the Coyote Creek mine. The North Dakota Department of Environmental Quality (“NDDEQ”) finalized its state implementation plan and submitted it to the EPA for approval in August 2022. The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at Coyote Station power plant. Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be economically feasible for Coyote Creek's customers to invest in such equipment, which could result in early retirement of Coyote Station and the Coyote Creek mine. Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner 10 Table of Contents or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”. In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule; however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations. Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals. The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected. Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources. 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 resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities. The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, which preceded the ACE rule, the ACE rule limited "best system of emission reduction" to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and vacated the ACE rule. In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants. In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States granted certiorari. In June 2022, the U.S. Supreme Court reversed the D.C. Circuit’s decision on the ACE rule and remanded the case back to the D.C. Circuit. The EPA has indicated that it will draft a new rule to regulate carbon dioxide emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company’s business, financial condition or results of operations. The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021. The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025. Solar energy property placed in service after December 31, 2025 will receive a 10% ITC. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”). The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels and impact demand for fossil fuels. The ultimate impact on fossil fuel demand and the Company is uncertain and may change as 11 Table of Contents 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 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. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a 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 The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations. The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. 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. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR"). The new definition was challenged in court and two court cases resulted in vacatur of the NWPR. The Supreme Court of the United States heard the Sackett vs. EPA case in October 2022 that challenges how federal jurisdiction of wetlands should be determined. A decision is expected by June 2023. In the meantime, in January 2023, the EPA published a new rule that redefines WOTUS that relies on the significant nexus test established by the 2006 Rapanos decision. The new definition expands the scope of the federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands. 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 12 Table of Contents treatment trust. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire. Resource Conservation and Recovery Act The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule. One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. Additionally, the CCR Part B Final Rule allowed facilities to demonstrate that there is no reasonable probability of adverse effects to human health and the environment at non-conforming units. These new rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of the Company's mines. Any such closure of the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations. The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by 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 so that they may complete the environmental assessment. Historically, this process has been lengthy and may take several years to complete. In 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations; however, it was immediately challenged by states and non-governmental organizations. In April 2022, the CEQ issued a new draft rule rescinding many of the revisions from the 2020 update. In January 2023, the CEQ issued interim guidance that instructs federal agencies to quantify GHG emissions for each alternative and use the social cost of greenhouse gasses to calculate a monetary metric that gives decision makers and the public useful information and context about a proposed actions’ climate effects. The revised NEPA regulations and interim guidance could adversely affect the Company’s ability to secure necessary permits. 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 types, quantities and locations of production. The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline 13 Table of Contents 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. Environmental Matters Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on 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. 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. Drilling and Production 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 or "allowables"; • 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 14 Table of Contents 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. Regulation of Hydraulic Fracturing Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The 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. Endangered Species Act The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) 15 Table of Contents 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. Natural Gas Sales and Transportation Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, 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. Oil Sales and Transportation Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, 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. 16 Table of Contents State Regulation Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States 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. 17 Table of Contents INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following tables set forth as of March 1, 2023 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. EXECUTIVE OFFICERS OF THE COMPANY Name Age Current Position J.C. Butler, Jr. 62 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018) Elizabeth I. Loveman 53 Vice President and Controller and Principal Financial Officer (from prior to 2018) John D. Neumann 47 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018) Thomas A. Maxwell 45 Vice President - Financial Planning and Analysis and Treasurer (from prior to 2018) PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES Name Age Current Position J.C. Butler, Jr. 62 President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018) Carroll L. Dewing 66 Vice President - Operations of NACoal (from prior to 2018) John D. Neumann 47 Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018) J. Patrick Sullivan, Jr. 64 Vice President and Chief Financial Officer of NACoal (from prior to 2018) 18 Table of Contents