nacco-20241231
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
For the fiscal year ended December 31, 2024
or
Commission File No. 1-9172
NACCO INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (440) 229-5151
Securities registered pursuant to Section 12(b) of the Act
Title of each class Trading Symbol Name of each exchange on which registered
Class A Common Stock, $1 par value per share NC New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: Class B Common Stock, $1 par value per share. Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ̈Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ̈Noþ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ No £
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yesþ No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐No☑
Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2024 (the last business day of the registrant's most recently completed second fiscal quarter): $117,744,151
Number of shares of Class A Common Stock outstanding at February 28, 2025: 5,866,937
Number of shares of Class B Common Stock outstanding at February 28, 2025: 1,565,359
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Proxy Statement for its 2025 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.
NACCO INDUSTRIES, INC.
TABLE OF CONTENTS
PAGE
PART I.
Item 1. BUSINESS 1
Item 1A. RISK FACTORS 18
Item 1B. UNRESOLVED STAFF COMMENTS 27
Item 1C. CYBERSECURITY 28
Item 2. PROPERTIES 29
Item 3. LEGAL PROCEEDINGS 48
Item 4. MINE SAFETY DISCLOSURES 48
PART II.
Item 6. [RESERVED] 49
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 64
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 64
Item 9A. CONTROLS AND PROCEDURES 64
Item 9B. OTHER INFORMATION 64
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 64
PART III.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 65
Item 11. EXECUTIVE COMPENSATION 65
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 65
PART IV.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 66
SIGNATURES 72
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA F-1
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PART I
Item 1. BUSINESS
General
NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources and with NACCO collectively, the Company, we, our or us), bring natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate 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 as well as comprehensive reclamation and restoration construction services. In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.
We have items not directly attributable to a reportable segment that are not included in the reported financial results of the operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, and the financial results of Bellaire Corporation (Bellaire), Mitigation Resources, ReGen Resources and other developing businesses. Bellaire manages our 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 operate under the umbrella of NACCO Natural Resources. Management continues to view our long-term business outlook positively. Our businesses provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and chemicals. Increasing demand for electricity, on-shoring and current federal policies are creating favorable macroeconomic trends within these industries. Management is confident in our trajectory and business prospects as well as longer-term growth opportunities.
While we realize the coal mining industry continues to face challenges, we believe the current political environment may change the sentiment surrounding fossil fuel industry-related regulations. These developments are expected to further support coal as an essential part of the energy mix in the United States for the foreseeable future.
NAMining is our primary platform for growth around mining activities. With a focus on operational excellence, scalability and driving profitable growth, NAMining expects to improve operating margins as well as achieve additional growth through its ongoing business development activities. New contracts and contract extensions are central to the business' organic growth strategy. The goal is to continue NAMining's ongoing expansion as a leading provider of contract mining services for customers who produce a wide variety of minerals and materials, and we expect NAMining to be a substantial contributor to operating profit over time.
The Minerals Management segment, through our Catapult business, has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests in the United States that is expected to deliver near-term cash flow yields and long-term growth. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids, typically net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The current portfolio provides a strong foundation of well-positioned assets that are expected to continue to deliver solid financial results. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the full cost of exploration, production and/or development. We intend to continue these activities, while at the same time evaluating investments in non-operated working interests that we believe can reliably increase cash flow and enhance overall returns. As a non-operator, we seek to diversify our investment and operational risk through participation in oil and gas wells with multiple operators across multiple basins. While the timing of returns could vary, we maintain a long-term perspective and believes the Minerals Management segment will provide unlevered after-tax returns on invested capital in the mid-teens as the business matures.
Mitigation Resources, which provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services, continues to build on the substantial foundation it has established over the past several years. Our Mitigation Resources business offers an opportunity for growth and diversification in an industry where we have a strong
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reputation as well as substantial knowledge and expertise. In addition, Mitigation Resources is providing ecological restoration services for abandoned surface mines and was named a designated provider of abandoned mine land restoration by the State of Texas. Mitigation Resources is working to develop a protected habitat for toads in Texas, as well as pursuing additional environmental restoration projects. We believe that Mitigation Resources can provide solid rates of return on capital employed as this business matures. As of December 31, 2024, we have 11 mitigation banks and other mitigation projects located in Alabama, Florida, Georgia, Mississippi, Pennsylvania, Tennessee and Texas.
We believe our businesses have competitive advantages that provide value to customers and continuing to invest in our businesses can create long-term value for stockholders. We have strategically leveraged our core mining and natural resources management skills to build a robust portfolio of affiliated businesses and opportunities for additional growth remain strong. Acquisitions of additional mineral interests and improvements in the outlook for Coal Mining segment customers, as well as new contracts at Mitigation Resources and NAMining and development of other business opportunities should be accretive to our longer-term outlook.
NACCO also continues to pursue activities which can strengthen the resiliency of our existing coal mining operations. We remain 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 our Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices, weather and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants.
We continue to look for ways to create additional value by utilizing our core mining competencies, which include reclamation and permitting. NACCO established ReGen Resources to utilize these skills to address the rapidly increasing demand for additional power generation sources in the United States through development of energy-related projects that utilize multiple generation technologies, such as solar combined with gas-fired generation, primarily on reclaimed mining properties. These projects could be developed by ReGen Resources directly or through joint ventures that include partners with expertise in energy development projects and their financing. Current opportunities in development include solar arrays, solar-gas hybrid projects and carbon capture on reclaimed mine land in Mississippi and Texas, as well as early-stage review of projects in other states.
NACCO is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. We believe strategic diversification will generate cash that can be re-invested to strengthen and expand our businesses. We also continue to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.
Business Developments
Coal Mining Segment
During 2023, Mississippi Lignite Mining Company (MLMC) received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed MLMC's long-lived assets for impairment and recorded a $65.9 million impairment charge in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.
The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas. All production from Sabine was delivered to
Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American
Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.
NAMining Segment
Sawtooth Mining, LLC (Sawtooth) will be the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada. Thacker Pass is owned by a joint venture between Lithium Americas Corp. (TSX: LAC) (NYSE: LAC) and General Motors Holdings LLC. Thacker Pass commenced construction in 2023 and is targeting initial production in 2027. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services,
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Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.
During 2024 and 2023, NAMining amended and extended existing limestone contracts with two customers and expanded the scope of work with several other customers. New contracts signed in 2024 are expected to be accretive to earnings starting in 2026.
Minerals Management Segment
During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of
2024, in Eiger, LLC (Eiger), which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.
During 2023, Minerals Management acquired $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin.
Other Items
In December 2023, we entered into a power purchase agreement with the Tennessee Valley Authority (TVA) for the energy generated from a proposed 67.5 MW solar photovoltaic electric generation facility to be developed on reclaimed land at our Red Hills Mine. The development of this project is subject to the favorable completion of an Environmental Assessment under the National Environmental Policy Act (NEPA) and approval of an interconnection agreement with TVA. In addition, we entered into an engineering, procurement and construction agreement related to the interconnection of the project during 2025. The estimated commercial operation date for this generation facility is late 2027.
Operations
Coal Mining Segment
The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with our customer's operations.
As of December 31, 2024, the Coal Mining segment's operating coal mines were: The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and MLMC. Each of these mines supply lignite coal for power generation and delivers our coal production to an adjacent power plant or synfuels plant under a long-term supply contract. While MLMC’s coal supply contract contains a take or pay provision, the contract contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party; all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.
The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our 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's customer operates the Red Hills Power Plant, which supplies electricity to TVA under a long-term power purchase agreement. MLMC’s contract with its customer runs through April 1, 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC.
At Coteau, Coyote Creek and Falkirk, we are 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. Our 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 us. 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
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is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our 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 our 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 our consolidated U.S. tax return; therefore, the Income tax benefit 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.
We perform contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, our 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.
See Item 2. Properties on page 29 in this Form 10-K for discussion of our 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 our 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 our customers by performing the mining aspects of our customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of December 31, 2024, NAMining operates in Florida, Texas, Arkansas, Virginia and Nebraska.
In addition, Sawtooth will supply all of the lithium-bearing ore requirements for Thacker Pass, which is currently in the development stage with construction activities underway. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services, Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.
Minerals Management Segment
The Minerals Management segment derives income primarily by leasing our 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, non-participating royalty interests and overriding royalty interests (collectively mineral and 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 have 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
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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.
We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own 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 does not currently have any material investments under which it would be required to bear the cost of exploration, production or development. The Minerals Management segment will benefit from the continued development of our mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired as the capital costs or lease operating expenses are born entirely by the operators or working interest owners.
During 2024 and 2023, Minerals Management invested a total of $19.1 million, including $15.7 million in the fourth quarter of
2024, in Eiger, which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. This entity meets the definition of a VIE. NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, this contract is accounted for as an equity method investment. During 2024, we recorded $0.6 million, which represented our share of earnings, as Earnings of unconsolidated operations on the Consolidated Statements of Operations. Our investment is reported on the line Equity method investment in Eiger, LLC in the Consolidated Balance Sheets. Due to a lag in Eiger's financial reporting, earnings or losses from this investment will be recorded on a one quarter lag.
Excluding the Eiger investment described above, total consideration for the acquisitions of mineral and royalty interests was $0.7 million and $36.7 million, in 2024 and 2023, respectively. The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres. The 2023 acquisitions included 43.4 thousand gross acres and 2.5 thousand net royalty acres.
We also manage 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 our legacy reserves were acquired as part of our historical coal mining operations.
Total oil and gas mineral and royalty interests include approximately 198.4 thousand gross acres and 63.9 thousand net royalty acres at December 31, 2024. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.
See Item 2. Properties on page 29 in this Form 10-K for discussion of our 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, we have 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, including price, on which such volumes are marketed and sold.
In 2024 and 2023, three customers and two customers, respectively, accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:
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Percentage of Consolidated Revenues
Coal Mining customer 29 % 40 %
NAMining customer 24 % 22 %
NAMining customer 11 % 7 %
The loss of any of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on our consolidated results of operations.
Competition
Coteau, Coyote Creek, Falkirk and MLMC each have only one customer for which they extract and deliver coal. Our coal mines are directly adjacent to our customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems. All of the mines in the Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal being mined.
The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on pricing of renewable energy and our 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 our reserves will depend upon the interaction of these factors.
Coal-fired electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal. Fluctuations in natural gas prices and the availability of renewable energy sources, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Over the longer term, we continue to believe that customer demand will remain pressured by regulations mandating or incentivizing the purchase of power from subsidized renewable energy sources, particularly wind and solar. See Item 1. Business — Government Regulation on page 9 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, we believe we were one of the ten largest coal producers in the U.S. in 2024 based on total coal tons produced.
NACCO believes that we were the largest dragline operator in the U.S. in 2024.
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; we primarily compete 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 our 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 we can, which would adversely affect our 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 our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business
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conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Seasonality
We have experienced limited variability in our 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 our 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. In addition, demand for coal-fired power generation can increase due to unusually hot or cold weather as consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for coal-fired power generation.
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, significant weather events, 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 our control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, our lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices during the first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations. Due to these seasonal fluctuations, Minerals Management results of operations for individual quarterly periods may not be indicative of the results that may be realize on an annual basis.
Human Capital
As of December 31, 2024, we had approximately 1,700 employees, including approximately 1,100 employees at our unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes we have good relations with our employees.
Market-Based Compensation: We believe our employees are critical to our success and we invest in our 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. We offer a 100% 401(k) matching contribution up to 5% of compensation, which is immediately vested. Additionally, NACCO offers a generous profit-sharing contribution for all of our full-time and part-time employees. We provide 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;
•Identity protection benefits;
•Charitable donation matches; and
•Employee assistance program.
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Employee Development: We recognize that our culture and success is strengthened when employees are respected, motivated and engaged. We work to match employees with assignments that capitalize on the skills, talents and potential of each employee, and provides opportunities for professional growth. NACCO believes training is a critical component of employee well-being and growth. Training ranges from equipment-specific task training and enhanced safety procedures to strategic leadership and management training, ethics training and role-specific training. Employees are encouraged to pursue continued professional development, skills training and other educational opportunities. Qualified employees are eligible to participate in a tuition reimbursement program to advance their formal education. We believe 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 our core values. We are 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 our incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data. We have earned more than 100 safety awards at the state and national levels since the 1980s. NACCO strives to have zero safety incidents or injuries. Our operations have onsite safety personnel who train employees in safe work practices, review safety-related incidents and recommend improvements when appropriate. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. We believe 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. Every employee is responsible and accountable for safety performance.
Company Ethics: We have processes in place for compliance with our Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of our Directors and employees annually complete certifications with respect to compliance with our Code of Corporate Conduct. In addition, all of our employees 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. All NACCO personnel are required to report without delay any conduct which they believe to be illegal or a violation of our policies. The identity of any NACCO personnel making such a report is kept in strict confidence except as required by law, and we utilize a third-party hotline to ensure reports can be generated anonymously. Retaliation in any form against an individual who exercises their right to make a complaint in good faith is strictly prohibited.
Community Engagement: We value our local communities and provide support through volunteer activities, financial contributions and well-paying jobs. NACCO believes in making long-term investments in the areas where we operate by supporting numerous charitable efforts, including educational, arts and community organizations. Community engagement is encouraged and supported through our matching gift program. We will match employee contributions up to $5,000 per employee if program criteria are met.
Please visit nacco.com/stewardship/ for the full text of certain NACCO stewardship policies.
Available Information
We make our 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 our 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 our 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 our 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 us and other issuers that file electronically with the SEC.
Under Rule 12b-2 of the Exchange Act, we qualify as a smaller reporting company because our public float as of the last business day of our most recently completed second quarter was less than $250 million. For as long as we remain a smaller reporting company, we 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.
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Government Regulation
Our 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 our Coal Mining segment.
Numerous federal, state and local governmental permits and approvals are required for coal mining operations. Our subsidiaries hold or will hold the necessary permits at all of our lignite coal mining operations. At the coal mining operations where our subsidiaries hold the permits, we are 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.
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 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
Our 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. We have 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.
The election of Donald Trump, paired with Republican control of Congress, is likely to have a significant and favorable impact on the regulatory environment, particularly for fossil fuels. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed.
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.
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SMCRA establishes operational, reclamation and closure standards for surface coal mines. We accrue for the costs of final mine closure, including the cost of treating mine water discharges, at mines where our subsidiaries hold the mining permit. While these obligations are largely unfunded, they can require securitization through bonding, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.
SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the EPA), the U.S. Army Corps of Engineers and the Office of Surface Mining Reclamation and Enforcement (OSMRE) have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.
Greenhouse Gas (GHG) Emissions
The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides (NOx), mercury, particulates and other matter. Federal and 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 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.
In May 2024, the EPA published the final rules for GHG emissions and Mercury Air Toxics Standards (MATS) in the Federal Register. The final MATS and GHG rules will require compliance as early as 2027 and 2032, respectively.
Previous efforts by the EPA were met with extensive litigation and there has been a similar response to the new GHG and MATS rules. State coalitions have filed lawsuits challenging both of these rules. Several other entities, including electric generators and industry groups, have joined the lawsuits. In July 2024 and October 2024, stay motions for the GHG and MATS rules were denied by the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit Court), respectively. Following the D.C. Circuit Court denial, emergency stay motions were filed for the GHG and MATS rules with the Supreme Court of the United States (SCOTUS). In October 2024, the SCOTUS denied the stay applications for the GHG and MATS rules. The GHG and MATS cases continue through the normal procedures in the D.C. Circuit Court without stays in place. On February 19, 2025, the D.C. Circuit granted an EPA motion to hold the GHG case in abeyance for 60 days while the new EPA evaluates its position on the GHG rule. Similarly, on February 20, 2025, the D.C. Circuit granted an EPA motion to hold the MATS case in abeyance and removing the case from the upcoming oral argument calendar while the new EPA evaluates its position on the MATS rule.We cannot predict the full impact of the MATS and GHG rules on the operations of the coal-fired generation facilities operated by our customers; however, if the rules go into effect, the additional compliance costs could have a material adverse effect on our Coal Mining segment.
The GHG standards are based on technologies such as carbon capture and sequestration/storage and natural gas co-firing. The compliance deadline for existing coal-fired, steam generating electric generating units (EGUs) planning to install carbon capture and sequestration/storage technology has been extended to January 1, 2032 for plants that intend to operate beyond 2039. If a coal-fired plant intends to close prior to 2032, no controls will be required and if a plant plans to close between 2032 and 2039, they must begin co-firing with natural gas by January 1, 2030.
The MATS rules finalize changes for the filterable particulate matter surrogate emission standard for non-mercury metal hazardous air pollutants for existing coal-fired EGUs, the filterable particulate matter emission standard compliance demonstration requirements, and the mercury emission standard for lignite-fired EGUs. Review of the MATS rules indicate that the EPA significantly reduced the fine particulate matter emission standard for all existing coal-fired EGUs and will require continuous monitoring equipment to demonstrate compliance. Furthermore, the EPA elected to remove the lignite subcategory for mercury limits and will require lignite-fired EGUs to meet the same standard as other types of coal.
The recent change in presidential administrations, recent executive actions, and the resulting changes at the EPA make it unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed. The various parties are working through the legal and administrative processes and the actual outcome remains unknown at this time.
The CAA requires the EPA to review national ambient air quality standards (NAAQS) every five years to determine whether revisions to current standards are appropriate. In addition, states are required to submit to the EPA revisions to their state implementation plans (SIPs) that demonstrate the manner in which the states will attain NAAQS every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for
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revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to affect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone and nitrogen oxides. Our coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision. On May 6, 2024, the EPA lowered the level for particulate matter by 25%. States are required to update their state implementation plans by February 2027. The rule is currently being challenged at the D.C. Circuit by a coalition of states led by Kentucky and West Virginia. Oral argument was held at the D.C. Circuit on December 16, 2024.
In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address interstate transport of pollutants. While the CSAPR affects states in the eastern half of the U.S. and Texas, it does not affect EGUs in North Dakota. This rule imposes
additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began
implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective.
In 2019, certain states submitted SIPs to the EPA in response to the 2015 ozone standard reduction. On February 13, 2023, the EPA rejected the SIPs. The EPA’s action to deny the SIPs was challenged in various courts, including the 5th Circuit Court of Appeals (the Fifth Circuit). The Fifth Circuit issued a stay of the SIP rejection in Texas, Louisiana, and Mississippi which prevents the federal implementation plan (FIP) from going into effect pending the outcome of the litigation challenges.
On June 5, 2023, the EPA published the FIP in the Federal Register. The FIP decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stay beginning in 2024 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. On July 31, 2023, the EPA promulgated an interim rule (Interim FIP) that addresses the various judicial orders where the SIP rejection has been stayed. The Interim FIP requires these states to return to the previously approved NOx trading program and emission caps. The Interim FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the power plants in these states under the Group 2 trading program.
In June 2024, the SCOTUS decided to stay the rule pending further review on the merits because the EPA's justifications were flawed. The Ozone Transport Rule was premised on its applicability to 23 states, but litigation resulted in the removal of 12 of those states that accounted for over 70 percent of the emissions the EPA had planned to address. The EPA purported to select control measures that would maximize cost effectiveness in achieving downwind ozone air quality improvements, but it did so based on an assumption that all 23 states would apply the uniform levels of controls required by the FIP. The case was remanded to the D.C. Circuit where the parties fully briefed the case. Subsequent to briefing, the EPA asked to partially remand the rule to "take a supplemental final action addressing the record deficiency preliminarily identified by the Supreme Court." The EPA finalized the supplemental response in December 2024. On February 6, 2025, the EPA filed a motion requesting abeyance of litigation for 60 days to allow a transition to the new administration. On February 21, 2025, the D.C. Circuit denied the EPA's request to hold the litigation in abeyance and extending the briefing schedule through March 27, 2025.
Should the FIP be fully implemented in states where a stay has been issued, the rule could influence the closure of some coal-fired EGUs that have not installed selective catalytic reduction technologies, potentially including the EGU supplied by MLMC. We cannot predict the outcome of the legal challenges to the: (i) various state challenges; (ii) the FIP promulgated on June 5, 2023; (iii) the interim final rule promulgated on July 31, 2023; nor (iv) the supplemental response dated December 10, 2024 that seeks to address the judicial orders. If the original FIP withstands legal challenge, it would increase the cost of operating the customer facility serviced by MLMC.
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. State implementation of the EPA’s Regional Haze Rule could require our North Dakota customers to incur significant new costs at their respective power plants, which could result in the premature closure of such power plants and their associated mines. 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 the North Dakota power plants. In July 2024, the EPA issued a proposed partial denial of the state implementation plan. We submitted comments to the EPA on the proposed partial denial during the third quarter of 2024 and have filed a petition for review with the Eight Circuit Court of Appeals. The State of North Dakota, several of our customers, and others have also filed petitions for review. On February 27, 2025, the EPA filed an unopposed motion to hold these consolidated cases in abeyance for 120 days while the new administration evaluates its position on the partial denial of the state implementation plan. Notwithstanding NDDEQ’s determination, the EPA may require additional costly emission controls and it may not be
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economically feasible for our North Dakota customers to invest in such equipment, which could result in early retirement of our customers' power plants and our associated mines.
Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. These new rules may raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive, and/or result in early closure of the coal-fired EGU's operated by our customers 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 our coal mines. We cannot predict the full impact of the various GHG and CAA rules on the operations of the coal-fired EGUs operated by our customers and any early closure of our mines could have a material adverse effect on our business, financial condition and results of operations.
The Trump administration is expected to direct the EPA to reconsider and revise or rescind the EPA’s rules regulating emissions from power plants, among other regulatory actions affecting power generation, and has already issued executive orders aimed at this outcome. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. Although we anticipate the EPA’s review of such regulations likely will result in less stringent requirements, we cannot predict the outcome of any final EPA actions or court challenges to such final actions.
Clean Water Act
CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for wastewater
discharge, including from coal mines.
In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States (WOTUS.) On May 25, 2023, the SCOTUS issued its Sackett vs. EPA ruling that defined WOTUS as “a relatively permanent body of water connected to traditional interstate navigable waters” with a “continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.” As a result of the Sackett decision, the EPA and the Army Corps of Engineers authored a revised definition of WOTUS and promulgated a final rule. The new rule does not go into effect in states where a stay had been issued for the previous rule, including North Dakota, Texas, Louisiana, and Mississippi. In these states, the legal challenges to this rule have resumed. In the meantime, securing CWA permits may be more challenging since the agencies in the states where a stay has been issued have less guidance to rely on to determine whether certain features are considered WOTUS. To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our coal mining operations.
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. In 2004, Bellaire was notified by the Pennsylvania Department of Environmental Protection that it was required to establish a mine water treatment trust to serve as a long-term funding mechanism related to this obligation. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.
These federal and state requirements could require more costly water treatment and could materially adversely affect our business, financial condition and results of operations.
Resource Conservation and Recovery Act
RCRA affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including
hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous
waste management. In 2020, the EPA finalized changes to the coal combustion residual (CCR) rule that classified all clay-lined surface impoundments that receive CCR as unlined. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of disposal capacity with a deadline to initiate closure and a new site-specific alternative due to permanent cessation of coal-fired boilers with deadlines to complete closure.
In May 2023, the EPA published proposed regulations that would impose federal regulatory requirements for previously
exempt inactive CCR surface impoundments at inactive facilities (legacy CCR surface impoundments). In May 2024, the EPA published a final rule amending CCR regulations which introduces new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired power plants with a legacy surface impoundment. The regulations impose new requirements including groundwater monitoring, closure standards, post-closure care obligations, and potential remediation activities.
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These rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of our mines. Any such closure of our mines could have a material adverse effect on our business, financial condition and results of operations.
In compliance with these regulations, Falkirk's customer, the owner of the Coal Creek Station power plant, submitted a CCR Part B application to the EPA in 2020 asserting a unit complied with the CCR rules. In the first quarter of 2023, the EPA proposed to deny the owner’s application. The owner and other parties have submitted additional information and comments supporting the owner’s position. If the EPA ultimately denies the owner’s application, a new liner may need to be installed or new waste management processes and/or units may need to be constructed. Accordingly, it is possible that a denial by the EPA could require a temporary unit shut down. Any temporary unit shut down could result in a temporary suspension of operations at Coal Creek Station. To minimize any impact to operations, Coal Creek Station continues to work with the EPA and is moving forward with plans to dry CCR materials produced by the plant, reducing the need to utilize the lined area in question. Falkirk is the sole supplier of lignite coal to Coal Creek Station. Any suspension of operations at Coal Creek Station would eliminate the need for lignite coal during the suspension period. Any such suspension of operations at Coal Creek Station or any of the power plants supplied by our mines could have a material adverse effect on our business, financial condition and results of operations.
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, we provide the required
information to the appropriate federal agency to enable it to complete the required study. Historically, this process has been
lengthy and may take several years to complete. In January 2023, the White House Council on Environmental Quality (CEQ)
issued interim guidance that instructs federal agencies to quantify GHG emissions and use the social cost of greenhouse gases to calculate a monetary metric associated with the proposed actions’ climate effects. The NEPA and interim guidance could adversely affect our ability to secure necessary permits.
On June 3, 2023, President Biden signed the Fiscal Responsibility Act of 2023 into law, which included certain provisions
collectively known as the Builder Act. The Builder Act includes amendments to NEPA which codify past regulatory reforms,
including narrowing what qualifies as a major federal action, limiting the scope of NEPA review to “reasonably foreseeable
environmental effects,” narrowing consideration of cumulative effects, directing agencies to only consider technically and
economically feasible reasonable alternatives and providing page limits and timelines for environmental impact statements and
environmental assessments. In April 2024, the CEQ finalized the revised NEPA rules.
On February 16, 2025, CEQ issued a notice that it intends to rescind all CEQ NEPA implementing regulations. These actions have raised significant questions regarding how CEQ’s NEPA regulations and agency-specific NEPA procedures will be interpreted and enforced going forward. We are unable to predict what impact the new CEQ guidance will have on our ability to obtain governmental permits.
Federal Coal Leasing
We enter into leases of Federally owned coal for a small portion of the coal mined at certain of our North Dakota mines. In July 2024, the Department of Interior’s Bureau of Land Management (BLM) published its North Dakota Proposed Resource Management Plan (RMP), which provided that no Federal coal which lies more than four miles away from a currently existing surface coal mining permit will be available for future leasing in North Dakota. In September 2024, the Company, along with other stakeholders, including the Governor of North Dakota, filed protests against the RMP. The BLM denied the protests and published the final RMP in January 2025. The State of North Dakota filed a challenge to the RMP in the United States District Court for the District of North Dakota on February 25, 2025. We are currently evaluating a similar challenge. If any such challenges are not successful, we may be required to alter our mine plans to avoid areas of Federal coal in the future.
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, 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 us any differently or to any greater or lesser extent than they affect other companies in the industry with similar assets.
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The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (FERC). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We 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 our 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 our mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
In December 2023, EPA finalized a rule that will require oil and gas producers to reduce methane and other air pollutants from existing sources. Oil and gas companies will be required to phase out routine flaring of natural gas and install methane leak detection equipment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.
In May 2024, the EPA finalized a rule containing revisions and additions to the New Source Performance Standards (NSPS) program rules (the Final Methane Rule). The Final Methane Rule formally reinstates emission limitations on methane, a GHG emission, for existing and modified facilities in the oil and gas sector. Specifically, the Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. Several states and industry groups have filed suit before the D.C. Circuit challenging the Final Methane Rule. On October 4, 2024, the SCOTUS denied applications for an immediate stay of the Final Methane Rule pending review by the D.C. Circuit Court of Appeals. Though the final outcome is uncertain, the rule establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources. The Final Methane Rule could have a significant impact on the upstream and midstream oil and gas sectors.
In November 2024, the EPA announced a final rule to reduce methane emissions from the oil and gas sector. The rule requires payment of a Waste Emissions Charge (WEC) on waste emissions of methane from certain oil and gas facilities. The Inflation Reduction Act-mandated fee would be triggered when companies report more than 25 metric tons of carbon dioxide equivalent per year to the EPA's Greenhouse Gas Reporting Program. The fee begins at $900 per metric ton of methane exceeding that threshold in 2024 and increases over time. A petition for review was filed in January 2025 by a coalition of Texas-led states and other industry groups. The fee could have a significant impact on the upstream and midstream oil and gas sectors.
Drilling and Production
The operations of the Minerals Management segment’s third-party lessees and our equity method investee 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
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wells, drilling bonds and generating reports concerning operations. The states, and some counties and municipalities, in which we have mineral interests also regulate one or more of the following:
•the location of wells;
•the method of drilling and casing wells;
•the timing of construction or drilling activities, including seasonal wildlife closures;
•the rates of production;
•the surface use and restoration of properties upon which wells are drilled;
•the plugging and abandoning of wells; and
•notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our 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 our 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 our 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 our mineral and royalty interests operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
On January 20, 2025, President Trump issued several executive orders that prioritized energy security, exploration and production on federal lands and processing of Liquefied Natural Gas export applications. Implementation of these executive orders could positively impact domestic drilling and production of oil and natural gas.
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.
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
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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 our mineral interests, including those held by our equity method investee, 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 our 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 our mineral interests or our equity method investment.
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) 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 our 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 we hold 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 we hold 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, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on natural gas-related activities.
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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, we believe that the regulation of oil transportation rates will not affect our 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, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as they are to our competitors.
State Regulation
States regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. 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 we 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 and to limit the number of drilled wells or locations of our third-party lessee operators or of our equity method investment.
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. We do not believe that compliance with these laws will have a material adverse effect on our 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. We 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, we have 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, we may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect our 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 we are required to conduct our operations.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2025 the name, age, current position and principal occupation and employment during the past five years of our 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
PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES
Name Age Current Position
Item 1A. RISK FACTORS
We operate in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect our business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business.
Risks related to the Coal Mining segment
Termination of or default under long-term mining contracts could adversely affect our business, financial condition, results of operation and cash flows.
Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although we have long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure or contract default could have a material adverse effect on our business, financial condition and results of operations.
The coal mining industry is subject to ongoing complex governmental regulations and legislation that could adversely impact our long-term mining contracts and our results of operations, liquidity, financial condition and cash flow.
The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. We are required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and
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approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect our mining operations, cost structure or customers. All of these factors could significantly reduce our profitability.
Congress has considered climate change legislation aimed at reducing GHG emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions at the federal or state level, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups of coal-fired power plants, could result in electric generators switching from coal to other fuel sources or premature facility closures.
Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and cap-and-trade programs, and mandates or incentives to generate electricity by using renewable energy sources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, certain governmental agencies provide 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 potential impact on us 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 require electricity generators to diminish their reliance on coal as a fuel source. Complicating these matters further, over the last several decades, U.S. Administrations have increasingly relied on regulations and executive orders to implement environmental policies and objectives in the absence of Congressional agreement regarding new legislation. This condition, which creates instability and unpredictability of environmental regulations, seems likely to persist and could increase due to apparent polarization between the two main political parties. As a result, we and/or our customers, often must comply with and otherwise adapt to environmental regulations without assurance of their continued effect. We and/or our customers often do not have the ability to anticipate, or prepare in advance for, changes in regulatory approaches that may be implemented following a change in Administration. The SCOTUS’s recent decision in Loper Bright Enterprises v. Raimondo overturned the SCOTUS’s longstanding deferral to the applicable agency’s interpretation of ambiguous federal laws. We are unable to predict whether, or to what extent, this decision will alter the outcome of judicial reviews of current or future regulations. We do not know whether risks related to current and future regulations affecting us will be significantly mitigated by the decision in Loper Bright.
In view of the significant uncertainty surrounding each of these factors, it is not possible for us to predict reasonably the impact that any such laws, regulations or other policies may have on our business, financial condition and results of operations. However, such impacts could have a material adverse effect on our business, financial condition and results of operations.
See Item 1. Business — Government Regulation on page 9 in this Form 10-K for discussion of regulations that could materially adversely affect the Coal Mining segment.
The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect our business, financial condition, results of operation and cash flows.
Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of our control. If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on our profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if we are unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, our business, financial condition, results of operations and cash flows could be adversely affected. See Item 1. Business — Business Developments on page 2 in this Form 10-K for further discussion.
MLMC is subject to risks associated with our capital investment, operating and equipment costs, growing use of alternative generation that competes with coal-fired generation, changes in customer demand and inflationary adjustments.
The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, adverse mining conditions and growing competition from alternative power generation that competes with coal-fired generation. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs or decreased revenues could materially reduce our profitability.
Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established
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indices over time. All production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.
Diesel fuel is heavily weighted among the indices used to determine the coal sales price. The diesel fuel-related component of the coal sales price is based on average price changes over time whereas the impact on actual costs from changes in diesel fuel prices is more immediate; therefore, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.
Any reduction in customer demand at MLMC, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the customer's Red Hills Power Plant, economic conditions, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.
The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.
The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a management fee approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the Unconsolidated Subsidiaries' customers pay us our agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the Coal Mining segment's customers' facilities, economic conditions and governmental regulations could have a material adverse effect on our results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce our profitability.
Changes in coal consumption patterns of U.S. electric power generators could adversely affect our profitability.
The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.
Changes in the utility industry that affect NACCO's customers could also adversely affect us. The increased availability of renewable energy sources has contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants have the most potential to continue to displace a significant amount of coal-fired electric power generation. Federal and state mandates for increased use of electricity derived from renewable energy sources have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.
Any of these risks could result in a decrease in coal consumption by our customers and could have a material adverse effect on our business, financial condition and results of operations.
We are subject to burdensome federal and state mining regulations and the assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.
Federal and state statutes require us to restore mine property in accordance with specified standards and an approved reclamation plan, and require that we obtain and periodically renew permits for mining operations. Regulations require us to incur the cost of reclaiming current mine disturbance at operations where we hold the mining permit. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on our business and could significantly reduce our profitability.
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The Coal Mining segment's customers' operations require significant capital expenditures.
Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Mining segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.
We face numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Information concerning our mining operations in Item 2 - Properties on page 29 has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal at MLMC are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals, new mining or other data received.
There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond our control. While we believe that our mineral reserve and resource estimates are developed using well-established practices and with appropriate controls, mineral reserve and mineral resource estimation is an imprecise and subjective process. Estimates of mineral reserves and resources depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
•Geologic and mining conditions, including our ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;
•Demand for our minerals;
•Contractual arrangements, operating costs and capital expenditures;
•Development and reclamation costs;
•Mining technology and processing improvements;
•The effects of regulation by governmental agencies, including volatility in the political, legal and regulatory environments due to the U.S. presidential administration;
•The ability to obtain, maintain and renew all required permits;
•Employee health and safety; and
•Our ability to convert all or any part of mineral resources to economically extractable mineral reserves.
As a result, actual tonnage recovered, estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves and resources. Any material inaccuracy in estimates related to our reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect our business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC’s property disclosure requirements for mining companies.
A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine coal reserves or result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. We may not verify title to leased properties or associated coal reserves until we are committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and/or pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
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Risks related to the NAMining segment
We have experienced growth in our NAMining business in recent periods and we may not be able to sustain growth or manage future growth effectively.
We have expanded our overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as we scale the NAMining business. We must effectively integrate, develop and motivate employees, while integrating new equipment and customers in an efficient and effective manner. We anticipate that it will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If we are unable to manage this growth and the associated expenses effectively, we may not be able to take advantage of market opportunities or remain competitive. We may also fail to execute on our business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.
NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.
NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that our existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.
We are subject to risks involved in the development of new mining projects.
From time to time, we seek to develop new mining projects, including the Thacker Pass project. The risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays or reductions in making capital expenditures by NAMining's customers, timely regulatory approvals, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on our business, financial condition and results of operations.
NAMining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.
As of December 31, 2024, over 75% of the quarries NAMining operates are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for NAMining’s services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the NAMining business.
Risks related to the Minerals Management segment
We have no control over the timing of the development and operation of our natural gas, oil and coal reserves extracted by third parties.
We own mineral and royalty interests in the continental United States. 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. We primarily derive income from royalty-based leases under which lessees make payments to us based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on our mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by us, and depends on a number of factors outside of our control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, our lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where we own mineral and royalty interests, our lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay our royalty payments or continue operations. A failure on the part of the lessee to make royalty payments may give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. However, we may not be able to find a replacement lessee or might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if we are able to enter into a new
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lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce our expected royalty income and profitability.
Minerals are a depleting asset. Unless we replace existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, our reserves and royalty income will decline.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless our third-party lessees conduct successful ongoing well development activities or we continually acquire mineral and royalty interests, production and income related to our mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators’ success in developing our current and future mineral and royalty interests. These operators may not have access to the capital needed to develop our mineral interests. We may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve we use to project future royalty income is subject to numerous assumptions and limitations. Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce our expected royalty income and profitability.
Substantially all of the Minerals Management segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying our interests are sold. Prices of oil and natural gas are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
The Minerals Management segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in: supply and demand, including if energy supply exceeds demand; market uncertainty and a variety of additional factors that are beyond our control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including ongoing conflicts in foreign nations and associated oil and natural gas import bans as well as economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; volatility in the political, legal and regulatory environments due to the U.S. presidential election; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
The marketability of oil and natural gas production is dependent upon transportation, pipelines and refining facilities and continued operation of the U.S. power grid. Any limitation in the availability of these items could interfere with our third-party lessee’s ability to market oil and natural gas production and may adversely affect the Minerals Management segment’s financial condition or results of operations.
The marketability of our third-party lessee’s production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties as well as continued reliable operation of the U.S power grid. Any significant disruption in the U.S. power grid, gathering system or transportation, processing, or refining-facility capacity could reduce our third-party lessee’s ability to market oil production and may adversely affect the Minerals Management segment’s financial condition or results of operations.
Risks related to long-term growth strategy
Our investments in mitigation solutions, comprehensive reclamation and restoration construction services as well as solar and other energy-related development projects are subject to substantial risks and uncertainties.
There are risks associated with NACCO's ability to execute on our longer term growth strategy, including our investment in mitigation solutions, comprehensive reclamation and restoration construction services as well as clean energy projects through our Mitigation Resources of North America and ReGen Resources businesses, and our ability to develop and manage such projects profitably. These include political and regulatory developments that may make it more costly, or impossible, to pursue these business opportunities, logistical risks and potential delays related to construction, permitting and regulatory approvals; operational risk that the projects will not perform according to expectations; weather conditions or other factors beyond our
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control. All of the aforementioned risks could reduce the viability of project development. We have and will continue to incur costs in connection with these projects and the results of operations and/or return on investment could be negative or lower than anticipated and we may need to write-down the value of capitalized assets associated with these projects. Furthermore, our ability to forecast results may be hindered or inaccurate and the projects may not perform as predicted. Even if these projects are profitable in the long term, they may not be profitable in the short term, and results of operations are unlikely to be even quarter over quarter.
In addition, our investments in solar and other energy projects are dependent, in part, upon current state regulatory incentives and federal tax credits in order for the projects to be economically viable. These projects face the risk that the current state regulatory programs and tax laws may expire or be adversely modified and could have a material adverse effect on our operating results and financial condition.
Risks related to corporate structure
The amount and frequency of dividend payments made on NACCO's common stock could change.
The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions and other factors the Board of Directors may consider. Accordingly, holders of our common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.
The price of NACCO's securities may be volatile.
The price of our common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism; (v) announcements concerning NACCO, our customers or competitors; (vi) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (vii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of our common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in our common stock may not be able to resell their stock at or above the price they paid or at all. Further, we could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on our operating results.
NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to NACCO's stockholders. Provisions in our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.
Our stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.
Our Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of our management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for our Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require us to acquire any specific number of shares and may be modified, suspended, extended or terminated without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.
Repurchases under the stock repurchase program could affect the price of our Class A common stock. The existence of a stock repurchase program could cause the price of our Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for our Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of our Class A common stock may decline below the levels at which we repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program’s effectiveness. Furthermore, the stock repurchase program does not obligate us to repurchase any dollar amount or number of shares of our Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of our Class A common stock to decline.
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NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.
We are currently a smaller reporting company as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare our performance with other public companies.
NACCO cannot predict whether investors will find our common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for our common stock and the stock price may be more volatile.
Certain members of our extended founding family own a substantial amount of our Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.
We have two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2024, accounted for approximately 27 percent of our voting power. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2024, accounted for our remaining voting power. As of December 31, 2024, certain members of our extended founding family held approximately 36 percent of our outstanding Class A common stock and approximately 99 percent of our outstanding Class B common stock. On the basis of this common stock ownership, certain members of our extended founding family could have exercised approximately 82 percent of our total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to our certificate of incorporation and our sale or the sale of our assets. Because certain members of our extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, we may be a less attractive takeover target, which could adversely affect the market price of our common stock.
General Risk Factors
Our effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.
We are subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in our effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.
Current and future capital and credit market conditions could adversely affect our ability to obtain bank financing on reasonable terms.Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in our ability to maintain financing at current levels.
We may be unable to obtain financing on reasonable terms. Historically, we have addressed our liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. Our wholly-owned subsidiary has a revolving line of credit of up to $200.0 million that expires in September 2028. Our ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or refinance with terms that are as favorable as the existing terms of such indebtedness, could have a material adverse effect on our operating results and financial condition.
Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.
Federal and state laws require us to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation and black lung benefit costs, leases, transmission interconnection construction costs, power purchase agreement delivery obligations and other obligations. Future federal and state laws and regulations, regional transmission organizations and power purchase agreement customers may require higher amounts of financial security, including as a result of changes to certain factors used
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to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As we are required by state and federal law to have bonds or other acceptable security in place before mining can commence or for certain projects to move forward, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand other forms of collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on our liquidity and financial position. If we are unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our liquidity.
Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in our ability to maintain insurance coverage at current levels.
We hold a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because we are involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure us in the future. In addition, if we make significant insurance claims under our insurance policies, such claims may have a material adverse effect on our ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of our liability insurance coverage limits, could have a material adverse effect on our operating results and financial condition.
Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on us or expose us to new or additional risks.
Expectations relating to environmental, social and governance (ESG) matters have been rapidly evolving. Government organizations are enhancing or advancing legal, regulatory and disclosure requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. We could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. Investors may request that we implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, we may face reputational challenges in the event our ESG practices are inconsistent with the third-party views of acceptable ESG practices. Further, there is an increasing number of state-level anti-ESG initiatives in the United States that may conflict with other regulatory requirements or various stakeholders’ expectations. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.
We may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.
Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.
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Our business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if we experience a security breach, a cyber incident or cyber attack.
Like many other companies, we are the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers.
As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat our, or a third-party service provider's, security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications we may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.
A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of our business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and our reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.
We rely on information technology systems to operate our business and to record and process transactions; respond to customer inquiries; purchase supplies; provide services; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite our efforts, our information technology systems may be vulnerable, from time to time, to damage or interruption from user error, computer viruses, power outages, third-party intrusions and other technical malfunctions.
Through our business operations, we collect and store confidential information from our customers and vendors and personal information and other confidential information from our employees. Although we have taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate our or our vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact our ability to respond appropriately.
We could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt our operations, damage our reputation, and expose us to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on our business, financial condition and results of operations.
Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support our activities could impact the business. We are continuously installing new and upgrading existing information technology systems. We use employee awareness training around phishing, malware, and other cyber risks. We believe these incidents are likely to continue and are unable to predict the direct or indirect impact of future attacks or breaches to business operations.
Our operations could be disrupted by natural or human causes beyond our control.