Core Natural Resources, Inc. (CNR) Business

ITEM 1.    BUSINESS

General

We are a world-class producer and exporter of high-quality, low-cost coals, including metallurgical and thermal coals. We play an essential role in meeting the world’s growing need for energy, steel, cement and other infrastructure solutions. Our products have global access due to our ownership interests in two marine export terminals and access to several other third-party owned terminals.

We and our predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. The Company was incorporated in Delaware on June 21, 2017 and became an independent, publicly-traded company on November 28, 2017 when our former parent separated its coal business and natural gas business into two independently traded public companies. We began regular-way trading under the name CONSOL Energy Inc. and ticker symbol CEIX on the New York Stock Exchange on November 29, 2017.

On January 14, 2025, we completed our all-stock merger of equals transaction with Arch pursuant to the Merger Agreement announced on August 21, 2024. Additionally, pursuant to the Merger Agreement, the Company was renamed “Core Natural Resources, Inc.” and began trading under the ticker symbol “CNR” on January 15, 2025.

The address of our principal executive offices is 275 Technology Drive, Suite 101, Canonsburg, Pennsylvania 15317. We maintain a website at http://www.corenaturalresources.com/. The information contained in or connected to the website will not be deemed to be incorporated in this Report, and you should not rely on any such information in making an investment decision.

All dollar amounts discussed in this section are in millions of U.S. dollars, except for per share amounts, and unless otherwise indicated.

Our Mission

The Company’s mission is to become the world’s leading provider of essential coal-based natural resources in support of human progress. We are committed to providing essential coal-based products necessary for infrastructure development, urbanization, transportation and reliable and affordable electric power generation. In doing so, we enable global prosperity and enhance the quality of life for people around the world. We are dedicated to the responsible utilization of vital natural resources, and we are committed to safe and sustainable practices that aim to reduce our environmental footprint, enhance our operations and create opportunities for our business and stakeholders. Our values of safety and compliance, continuous improvement and financial performance are the foundation of the Company’s identity and are the basis for how management defines continued success. We believe the Company’s rich resource base, coupled with our key values, will allow management to create long-term value for its stakeholders. We believe that the use of coal in industrial applications, including but not limited to the steel-making process, and as a fuel source for electricity will continue for many years.

Our Strategy

The Company continues to be focused on driving long-term value for its stakeholders and maximizing cash flow generation through the safe, compliant and efficient operation of our business, while maintaining a strong balance sheet and liquidity, returning capital through share repurchases and/or dividends and, when prudent, allocating capital toward compelling growth, diversification and innovation opportunities.

The Merger furthers this vision by combining best-in-sector metallurgical and thermal coal operating platforms anchored by high-quality, low-cost, long-lived longwall coal-mining assets. The Company has broad and diverse assets that produce coal with qualities and blends capable of serving multiple growth markets and geographies. In addition, the Company has strong North American logistics capabilities as well as export capabilities through ownership interests in two East Coast terminals and longstanding relationships with West Coast and Gulf Coast ports. The Company believes that the Merger will provide ongoing cash generation through a strong contracted thermal coal position coupled with meaningful opportunities across its metallurgical coal platform. The Company has the potential to return significant capital to stockholders while simultaneously making strategic investments in innovation and growth.

Leverage Our Low-Cost Assets and Diverse Product Qualities to Access Growing Export Metallurgical and Industrial Markets while Preserving the Revenue Visibility Provided by Coal Sales to Rail-Served Power Plants in Strategic Markets

We plan to minimize our market risk and maximize realizations by continuing to focus on placing a significant portion of our production in the export markets where we sell to metallurgical, industrial and electric power generation

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end-users. This approach provides us pricing upside when markets are strong and with volume stability when markets are weak. The Company has broad and diverse assets that produce coal with qualities and blends capable of serving multiple growth markets and geographies. In addition, the Company has strong North American logistics and export capabilities through ownership interests in two East Coast terminals and longstanding relationships with West Coast and Gulf Coast ports.

Prior to the Merger, approximately 57% of the Company’s 2024 sales tons were sold to export markets and 43% were sold to domestic customers. Of the 2024 sales tons, 49% were sold in the electric power generation market, 33% were sold in the industrial market and 18% were sold in the metallurgical market. After the Merger, approximately 28% of the Company’s 2025 sales tons were sold to export markets and 72% were sold to domestic customers. Of the 2025 sales tons, 73% were sold in the electric power generation market, 16% were sold in the industrial market and 11% were sold in the metallurgical market.

The rapid expansion of artificial intelligence and the construction of new data centers are driving a significant increase in global power demand, which presents a unique opportunity for the Company to benefit, as data centers require reliable and substantial sources of electricity to operate efficiently. As more data centers are built to support the growing needs of artificial intelligence technologies, the Company is positioned to pivot its production to meet increased coal demand.

Drive Operational Excellence through Safety and Compliance, Continuous Improvement and Financial Performance

We continue to focus on our values of safety and compliance, continuous improvement and financial performance. Following the Merger, our 2025 average lost-time incident rate was more than 2.3 times better than the industry average (based on preliminary underground and surface bituminous mining industry averages through June 30, 2025). We believe that our focus on safety and compliance promotes greater reliability in our operations, which fosters long-term customer relationships and lower operating costs that support higher margins. We intend to continue to grow the economic competitiveness of our operations by proactively identifying, pursuing and implementing efficiency improvements and new technologies that can drive down unit costs without compromising safety or compliance.

Preserve and Increase Cash Generation

The Company has generated significant cash provided by operating activities since becoming a publicly-traded company. We believe that the Company will continue to generate significant cash provided by operating activities across a range of market environments through the combination of revenue from contracted thermal coal production and sales, coupled with a strong metallurgical coal platform. The Company’s diversified exposure to different coal types also enhances its ability to provide a more consistent capital allocation strategy aimed at enhancing stockholder value creation.

Maintain Liquidity and Ability to Access Capital Markets

We constantly seek to improve our ability to access capital markets to provide additional funds, if needed, to grow our business and fund capital expenditures. We believe that our Company can access capital markets to raise debt and equity financing from time to time depending on the market conditions.

On January 14, 2025, and in connection with the Merger, the Company entered into an amendment to its existing Revolving Credit Facility (as defined in Item 1A of this Report). The amendment increased the aggregate revolving commitments from $355 million to $600 million and extended the maturity date of the facility to April 30, 2029, provided that, under specified conditions, the maturity of the Revolving Credit Facility may be earlier. The Revolving Credit Facility now includes participation from 22 banks, including nine new lenders, and 37% of the total commitments came from new lenders, while 63% were from existing lenders. Additionally, the Company reduced the applicable interest rate margin by 75 basis points while further enhancing financial flexibility.

In addition, on January 14, 2025, and in connection with the Merger, a subsidiary of Arch, Arch Receivable Company, LLC, as seller, and another subsidiary of Arch, Arch Coal Sales Company, Inc., as initial servicer, amended Arch’s receivables purchase agreement, which supports the issuance of letters of credit and requests for cash advances. The amendment permits the receivables purchase agreement to remain outstanding following consummation of the Merger, including by amending the change of control provisions thereunder. On July 28, 2025, the Company amended and restated legacy Arch’s securitization facility in its entirety to, among other things, consolidate facilities, extend the maturity date to July 27, 2028 and simultaneously terminate legacy CONSOL’s securitization facility.

Also, the Company has successfully accessed the tax-free municipal bond markets. On March 27, 2025, the Company successfully refinanced its Series 2025 Bonds (as defined in Item 1A of this Report) totaling $307 million at

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favorable rates while also extending the maturity to initial terms of ten years. Thirty-nine institutional investors participated in the transactions, which were more than six times oversubscribed on a cumulative basis.

Selectively Grow our Business to Maximize Stockholder Value by Capitalizing on Synergies with our Assets and Expertise

We plan to judiciously direct the cash generated by our operations toward those opportunities that create value for our stockholders, balancing shareholder returns with investments that leverage synergies with our asset base or the expertise of our management team. To that end, we intend to evaluate opportunities both for organic growth and for acquisitions, joint ventures and other business arrangements that complement our operations. For example, we are actively engaged in continuous improvement or research and development projects to improve the productivity of our mining operations through the use of technology, automation, data visualization and analytics.

Our management team has extensive experience in developing, operating and marketing a wide variety of coal and coal-related assets and, we believe, is well qualified to evaluate organic and external growth opportunities. We plan to carefully weigh capital investment decisions against alternate uses of the cash to help ensure we are delivering value to our stockholders.

The Company is also evaluating selective opportunities in critical minerals and advanced materials that leverage our extensive geological, mining, processing, technical and logistics expertise. These initiatives are intended to complement our existing coal asset portfolio and support long-term diversification, particularly in markets aligned with infrastructure development, advanced manufacturing, energy security and national strategic priorities. Rare earth elements (“REEs”), including but not limited to neodymium, praseodymium, dysprosium and terbium, are essential inputs for permanent magnets, electric vehicles, renewable energy systems, aerospace applications and defense technologies. The Company is assessing potential pathways to participate in portions of the rare earth value chain, including resource evaluation, recovery from coal-related feedstocks or waste streams, beneficiation and downstream processing technologies. These efforts are in early-stage evaluation and research phases and may include internal development, partnerships with academic institutions, government agencies, or third parties and potential strategic investments or joint ventures. Any such activities would be pursued in a disciplined manner, consistent with our capital allocation framework, environmental and safety standards and focus on generating long-term stockholder value. At this time, the Company has not recognized any material rare earth mineral reserves or resources under applicable Securities and Exchange Commission (“SEC”) reporting standards. The Company believes that its history and experience in large-scale resource extraction, materials handling, processing and compliance, together with its existing innovation platform, positions it to responsibly evaluate critical mineral opportunities as market conditions, technology readiness and regulatory frameworks continue to evolve.

We are also pursuing a variety of alternative and innovative uses of coal to diversify our business. These activities are led by CONSOL Innovations LLC (“Innovations”), our wholly-owned subsidiary with operations located in Triadelphia, WV, which is focused on creating long-term growth and diversification opportunities through sustainable innovations in the carbon products and materials and carbon management markets. For example, in 2022, we acquired the remaining equity stake in CFOAM Corp. (“CFOAM”), which manufactures high-performance carbon foam products from coal that can be used in the aerospace, military, industrial and commercial product markets. In 2023, we acquired the assets of Touchstone Advanced Composites (“TAC”), an innovative composite tooling supplier for the aerospace industry that uses our CFOAM product. Also in 2023, we expanded our research and development activities that are focused on using coal and coal mining/preparation plant waste streams for battery applications, including the development of battery anode materials, through an initial investment in C-BATT Innovations LLC (“C-BATT”). In 2024, we installed approximately 2,500 linear feet of our coal plastic composite decking product across several applications and entered aerospace parts manufacturing with the sale of our first TAC-manufactured parts. Additionally, two projects supported by our Innovations team were included on Time Magazine’s list of the 200 best inventions of 2024. In 2025, we continued to expand our aerospace parts manufacturing capabilities at TAC, became the majority owner of C-BATT and received a grant award from the Ohio Department of Development to help develop the first commercial-scale coal plastic composite deck board manufacturing line.

We also continue to partner with the U.S. Department of Energy (“DOE”) and certain industry and academic partners on several projects that are aligned with Innovations’ focus areas. Our DOE-sponsored REMEDY project seeks to develop an efficient, safe and cost-effective technology for mitigation of mine ventilation air methane that, if successful, could have broader market applicability.

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Our Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

World-Class, Well-Capitalized, Low-Cost Longwall Mining Complexes

Based on production per employee, the PAMC is a productive and efficient coal mining complex in the Northern Appalachian Basin (“NAPP”), averaging 7.45 tons of coal production per employee hour in 2025. We believe our substantial capital investment in the PAMC will enable us to maintain high production volumes, low operating costs and a strong safety and environmental compliance record, which we believe are key to supporting stable financial performance and cash flows throughout business and commodity price cycles.

Additionally, the Leer Complex longwall mines acquired through the Merger anchor our large-scale, first-quartile metallurgical franchise. The Leer Complex mines consistently rank among the lowest-cost U.S. metallurgical mines and produce a product quality that we believe is recognized and sought-after worldwide. These modern mines maintain a strong safety and environmental compliance record.

Extensive, High-Quality Reserve Base

The PAMC has extensive, high-quality reserves of bituminous coal. We mine our reserves from the Pittsburgh No. 8 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2025, the PAMC included 529.0 million tons of recoverable coal reserves that are sufficient to support approximately 20 years of full-capacity production, based on our current estimates. The advantageous qualities of this product enable us to compete for demand from a broad range of the global industrial and electric power generation markets. In addition to the substantial reserve base associated with the PAMC, our Leer Complex includes 170.2 million tons of recoverable coal reserves that are sufficient to support more than 30 years of full-capacity production, based on our current estimates, and this product is highly desirable for use in the global steel industry. Our remaining thermal and metallurgical reserves and resources provide additional optionality for organic growth or monetization as market conditions allow.

Strategically Located Advanced Distribution Capabilities and Access to Key Logistics Infrastructure

The Company’s logistics capabilities, anchored by terminal ownership, dual rail access, geographic diversity and advanced loadout infrastructure, constitute a core strategic advantage. These assets enable the Company to reliably deliver large volumes of coal to a global customer base, optimize costs and flexibly respond to shifting market dynamics, securing its position as a leading, resilient supplier in the coal industry.

The Company wholly owns the Core Marine Terminal, which is the only major East Coast coal terminal served by both Norfolk Southern and CSX railroads. It has a storage capacity of 1.1 million tons and a throughput capacity of approximately 20 million tons per year, primarily serving international customers. The Company also has access to the Dominion Terminal in Newport News, Virginia, operated by DTA, in which the Company holds a 35% interest, which has a 20-million-ton annual throughput and 1.7 million tons of ground storage, serving principally international customers.

Core’s Eastern mining complexes are directly served by Norfolk Southern and CSX, providing flexible and cost-effective access to major U.S. power plants and export terminals. Core’s Western operations (i.e., Black Thunder, Coal Creek, and West Elk) are connected to Burlington Northern Santa Fe and Union Pacific railroads, enabling efficient delivery to both domestic and export markets.

The Company’s mines are strategically located in Pennsylvania, West Virginia, Wyoming and Colorado, allowing it to serve a broad range of markets and customers with varying coal quality requirements. The proximity to both East and West Coast ports, as well as Gulf Coast connections, enhances export flexibility, reduces transportation costs and provides blending capabilities at terminals providing tailored coal products to customer specifications, thus increasing marketability.

Strong, Well-Established Customer Base Supporting Contractual Volumes

We have a well-established and diverse customer base, comprised of both domestic and international industrial customers, metallurgical end-users and electric-power-producing companies. We have had success entering into multi-year coal sales agreements with our customers due to our longstanding relationships, reliability of production and delivery, competitive pricing and high coal quality. Approximately 95% of our sales in 2025 were to customers that were in both our and Arch’s 2024 portfolio.

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We also have a growing international customer base due to favorable access to seaborne coal markets and our strong relationships with leading coal trading, brokering and international coal end-users. We have grown our exports of coal to the seaborne markets to 24.5 million tons (or approximately 62% of our annual high calorific value and metallurgical sales volume) in 2025 as a result of both growing our existing export business as well as the result of the Merger.

Highly-Experienced Management and Operating Teams

The Company is led by a proven and highly-experienced management team that combines the strengths and capabilities of both companies. Our management team is overseen by an experienced, majority-independent board of directors, currently comprised of six directors with a broad range of skills and experiences. Our management and operating teams have (i) significant expertise owning, developing and managing complex thermal and metallurgical coal mining operations, (ii) valuable relationships with customers, railroads and other participants across the coal industry, (iii) technical wherewithal and demonstrated success in developing new applications and customers for our coal products in industrial, metallurgical and electric power generation markets and (iv) a proven track record of successfully financing, building, enhancing and managing coal assets in a reliable and cost-effective manner throughout all parts of the commodity price cycles. We intend to leverage these qualities to continue to successfully develop our coal mining assets while efficiently and flexibly managing our operations to maximize operating cash flow and innovating to create long-term growth and diversification opportunities.

Focus on Free Cash Flow Generation Supported by Strong Margins and Optimized Production Levels

We intend to continue our focus on maintaining strong margins that drive generation of free cash flow by optimizing production from our high-quality reserves and leveraging our extensive logistics infrastructure and broad market reach. The Company has broad and diverse assets that produce coal with qualities and blends capable of serving multiple growth markets and geographies. To complement its coal portfolio, the Company has strong North American logistics and export capabilities through ownership interests in two East Coast terminals and longstanding relationships with West Coast and Gulf Coast ports. We believe that the Company is well-positioned from the Merger to provide ongoing cash generation through a strong contracted thermal coal position, coupled with meaningful opportunities through its expanded metallurgical coal platform.

For example, the PAMC’s low-cost structure, high-quality product, favorable access to rail and port infrastructure and diverse customer base allow it to move large volumes of coal at positive cash margins throughout a variety of market conditions and into multiple end-use markets. Additionally, the Leer Complex mines consistently rank among the lowest-cost U.S. metallurgical mines and produce a product quality that is recognized and sought-after worldwide. The Leer Complex is complemented by the Beckley, Mountain Laurel and Itmann continuous miner mines, which in aggregate provide us with a full suite of high-quality metallurgical products for sale into the global and domestic metallurgical markets. Additionally, the locations of our thermal mines in the Eastern and Western U.S. enable us to ship coal to most of the major domestic coal-fired power plants. Furthermore, our ability to enter into multi-year contracts with our longstanding customer base, as well as strategic industrial export customers, will enhance our ability to generate high margins in varied commodity price environments.

Principal Properties

Our significant tangible assets are the PAMC, the Leer Complex and the Core Marine Terminal, which have consistently generated strong free cash flows. As of December 31, 2025, the PAMC controlled 529.0 million tons of high-quality Pittsburgh seam reserves, enough to allow for an equivalent of approximately 20 years of full-capacity production, based on our current estimates. As of December 31, 2025, the Leer Complex included 170.2 million tons of recoverable coal reserves that are sufficient to support an equivalent of more than 30 years of full-capacity production, based on our current estimates.

After the Merger, our presence in the metallurgical coal market includes two longwall mines in the Leer Complex and three continuous miner mines, Beckley, Mountain Laurel and Itmann, all of which are in West Virginia. These mines produce a premium metallurgical product used in the global steel industry. We also operate thermal mines, including the PAMC, in Pennsylvania, Black Thunder and Coal Creek, in the PRB, as well as West Elk, in Colorado. The PRB mines produce thermal coal for sale into domestic and international markets. The PAMC and West Elk mines produce a high-quality, high calorific value thermal product that can compete effectively in seaborne markets where thermal coal demand remains robust. The Merger has also enabled the Company to gain access to a second export terminal, the Dominion Terminal, operated by DTA, in which the Company owns a 35% interest, on the U.S. Eastern seaboard, as well as strategic connectivity to ports on the West Coast and the Gulf of America.

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We are a global leader, exceptionally well-positioned to compete and succeed in significant, high-potential market segments, including the global metallurgical and global high calorific value thermal coal markets as well as domestic thermal coal markets broadly.

A map showing the location of our material properties is below:

Thermal Mining Properties

Our active thermal mines are described below:

•Pennsylvania Mining Complex: The PAMC includes the Bailey, Enlow Fork and Harvey mines and the Central Preparation Plant. Coal from the PAMC is valued because of its high energy content (as measured in Btu per pound), relatively low levels of sulfur and other impurities and strong thermoplastic properties that enable it to be used in metallurgical, industrial and electric power generation applications. We mine our reserves from the Pittsburgh No. 8 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high productivity, low-cost longwall mining operations. The design of the PAMC is optimized to produce large quantities of coal on a cost-efficient basis. We can sustain high production volumes at comparatively low operating costs due to, among other things, our technologically-advanced longwall mining systems, logistics infrastructure and safety. All mines at the PAMC utilize longwall mining, which is a highly-automated underground mining technique that produces large volumes of coal at lower costs compared to other underground mining methods. We aggressively market coal from the PAMC to a broad global base of diverse and strategically-selected industrial and metallurgical end users. We are able to transport coal from the PAMC to our customers through an extensive logistical network, which is directly served by both the Norfolk Southern and CSX railroads, coupled with the operational synergies afforded by the Core Marine Terminal. We also continue to support power plant customers in the eastern U.S. and abroad.

•Black Thunder: The Black Thunder surface mining complex, consisting of four active pit areas and two active loadout facilities, is located on approximately 35,300 acres in Campbell County, Wyoming and extracts thermal coal from the Upper Wyodak and Main Wyodak seams. It had approximately 331.5 million tons of proven and probable reserves at December 31, 2025. A significant portion of the coal reserves at Black Thunder are controlled through federal and state leases. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilities can load a 15,000-ton train in less than two hours.

•Coal Creek: The Coal Creek surface mining complex, consisting of one active pit area and a loadout facility, is located on approximately 7,400 acres in Campbell County, Wyoming and extracts thermal coal from the Wyodak-R1 and Wyodak-R3 seams. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000-ton train in less than three hours.

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•West Elk: The West Elk mining complex, consisting of one longwall and supported by continuous miner sections, a preparation plant and a loadout facility, is located on approximately 19,000 acres in Gunnison County, Colorado and extracts thermal coal from the B seam. It had approximately 31.5 million tons of proven and probable reserves at December 31, 2025. A significant portion of the coal reserves at West Elk are controlled through federal and state leases. We ship most of the coal raw to our customers via the Union Pacific railroad. When required to improve the quality of some of our coal production, it is processed through the 800 ton-per-hour preparation plant. The loadout facility can load an 11,000-ton train in less than three hours.

Metallurgical Mining Properties

Our active metallurgical mines are described below:

•Leer: The Leer mining complex, consisting of one longwall, a preparation plant and a loadout facility, is located on approximately 32,600 acres in Taylor County, West Virginia and extracts coal primarily sold as High-Vol A metallurgical coal from the Lower Kittanning seam. It had approximately 29.4 million tons of proven and probable coal reserves as of December 31, 2025. The majority of the reserves at Leer are owned rather than leased from third parties. All production is processed through a 1,400 ton-per-hour preparation plant and loaded on the CSX railroad. A 15,000-ton train can be loaded in less than four hours.

•Leer South: The Leer South mining complex, consisting of one longwall operation, a preparation plant and a loadout facility, is located on approximately 26,400 acres in Barbour County, West Virginia and extracts coal primarily sold as High-Vol A metallurgical coal from the Lower Kitanning seam, similar to our Leer mining complex. It had approximately 57.0 million tons of proven and probable reserves at December 31, 2025. The majority of the reserves at Leer South are owned rather than leased from third parties. The 1,600 ton-per-hour preparation plant is located near the mine, and the loadout facility is served by the CSX railroad and connected to the plant by a 4,000 ton-per-hour conveyor system. The loadout facility is capable of loading a 15,000-ton unit train in less than four hours.

•Beckley: The Beckley mining complex is located on approximately 14,900 acres in Raleigh County, West Virginia and extracts high quality, Low-Vol metallurgical coal from the Pocahontas No. 3 seam. It had approximately 22.6 million tons of proven and probable reserves at December 31, 2025. A significant portion of the reserves at Beckley are leased from third parties rather than owned. Coal is conveyed from the mine to a 600 ton-per-hour preparation plant before shipping the coal via the CSX railroad. The loadout facility can load a 10,000-ton train in less than four hours.

•Mountain Laurel: The Mountain Laurel mining complex is located on approximately 38,300 acres in Logan County and Boone County, West Virginia and extracts High-Vol B metallurgical coal from the Alma and No. 2 Gas seams. It had approximately 16.3 million tons of proven and probable reserves at December 31, 2025. We process all of the coal through a 1,400 ton-per-hour preparation plant before shipping the coal to our customers via the CSX railroad. The loadout facility can load a 15,000-ton train in less than four hours.

•Itmann: The Itmann mining complex is located on approximately 21,000 acres in Wyoming County, West Virginia and extracts high quality, Low-Vol metallurgical coal from the Pocahontas 3 and Pocahontas 4 seams. The Itmann mining complex had approximately 27.1 million tons of proven and probable coal reserves at December 31, 2025. A significant portion of the reserves at Itmann are leased from third parties rather than owned. The preparation plant includes a rail loadout located on the Guyandotte Class I rail line, which can be served by both Norfolk Southern and CSX, and has the capability for processing up to an additional 750 thousand to 1 million saleable tons annually from third-parties and mining of our surrounding reserves. This additional processing revenue provides an avenue of growth for the Company.

Terminals

Our ownership interests in two East Coast terminals are described below:

•Core Marine Terminal: Through our wholly-owned subsidiary, Core Marine Terminals LLC, we provide coal export terminal services through the Port of Baltimore. The terminal can either store coal or load coal directly into vessels from rail cars. It is also the only major East Coast coal terminal served by two Class I railroads, Norfolk Southern and CSX. During the year ended December 31, 2025, approximately 18.1 million tons of coal were shipped through the Core Marine Terminal. Approximately 83% of the tonnage shipped was produced by the PAMC. The Core Marine Terminal has storage capacity of 1.1 million tons with more than 30 acres of capacity for stockpiles. The facility possesses blending capabilities, and it has transloaded approximately 16.3 million tons of coal per year on average over the past five years with a throughput capacity of approximately 20 million tons. The facility primarily serves international customers.

•Dominion Terminal: We own a 35% interest in DTA, a limited liability partnership that operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. The facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons. The facility primarily

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serves international customers and domestic coal users located along the Atlantic coast of the U.S. From time to time, we may lease a portion of our port capacity to third parties.

Non-Core Coal Assets and Surface Properties

We own significant coal assets and surface properties that are not in our short or medium-term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures or a combination thereof in order to bring the value of these assets forward for the benefit of our stockholders.

Mining Properties as of December 31, 2025

Information concerning our mining properties in this Report has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires us to disclose our mineral resources and our mineral reserves as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.

As used in this Report, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. As such, you are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Likewise, you are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. We have used the term “coal” as in “coal reserves” and “coal resources” interchangeably with “mineral.”

The Company’s estimates of recoverable coal reserves and raw, in situ coal resources are estimated internally by professionals whom we believe to be competent, including engineers and geologists. These estimates are based on geological data, coal ownership information and current or proposed operating plans. The Company’s recoverable coal reserves are proven and probable reserves that could be economically and legally extracted or produced at the time of the reserve determination, considering all material modifying factors. These estimates are periodically updated to reflect past coal production, updated mine plans, new exploration information and other geological or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods or preparation plant processes may increase or decrease the recovery basis for the estimates. The ability to update or modify the estimates of the Company’s recoverable coal reserves is restricted to geologists and mining engineers whom we believe to be competent, and material modifications recommended by such geologists or engineers are documented by the Company. The Company’s estimates of recoverable coal reserves and raw, in situ coal resources and supporting information have been assessed by Weir International, Inc. and the John T. Boyd Company, qualified person firms, which conform to our requirements under subpart 1300 of Regulation S-K for qualified persons.

The information that follows relating to our material properties is derived, for the most part, from, and in some instances is an extract from, the technical report summary (“TRS”) relating to the property prepared in compliance with Item 601(b)(96) and subpart 1300 of Regulation S-K by Weir International, Inc. and the John T. Boyd Company. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, incorporated herein and made a part of this Report.

Recoverable coal reserves and raw, in situ coal resources are either owned or leased. The leases generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, reserves and resources reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.

The Company assigns coal reserves to mining complexes, and the amount of coal we assign to each mine is generally sufficient to support mining through the extent of our current mining permits. These permits were issued on various dates, and each are required to be renewed under federal law every five years. All assigned reserves either have their required permits or governmental approvals or there is a high probability that these approvals will be secured. In addition, our mines and mining complexes may have access to additional reserves that have not yet been assigned.

Some reserves may be accessible by more than one mine because of the proximity of many of our mines to one another. In the following tables, the reserves and resources indicated for a mine are based on our review of current mining plans and reflect our best judgment as to which mine is most likely to utilize the reserve. Certain reserves and resources in the following tables do not show balances for the comparative periods as these locations were acquired in the year ended December 31, 2025 in conjunction with the Merger.

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The following tables provide a summary of all the Company’s coal reserves and resources as of the end of the fiscal year ended December 31, 2025 (tons in millions):

Summary Material Coal Reserves

as of December 31, 2025

Summary Non-Material Coal Reserves

as of December 31, 2025

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Summary Coal Resources

as of December 31, 2025

(a) All resource tons reported as raw, in situ tons

(b) Other resources (by U.S. coal basin)

Internal Controls Disclosure

The modeling and analysis of the Company’s reserves and resources has been developed by Company engineering and geology personnel and reviewed by several levels of internal management. This section summarizes the internal control considerations for the Company’s development of estimations, including assumptions, used in reserve and resource analysis and modeling.

Records from exploration drilling completed on the mining properties comprise the primary data used in the evaluation of the coal resources for each property. The Company maintains written field and exploration guidelines that cover standard procedures, including site safety, mapping and how to select proper drilling equipment, record accurate and detailed geological logs, perform coal sampling, supervise geophysical logging and plug drill holes once work is complete.

The Company maintains all control of coal core samples up to the point that samples are handed over to the lab performing testing. Once logging and sampling are complete, the sampled coal core intervals are transported to the Company’s headquarters by exploration personnel, at which time they are handed over to quality personnel. The quality personnel arrange pickup by the selected independent lab that will perform the required analyses. All analytical work is conducted to International Organization for Standardization or ASTM International standards.

Management also assesses risks inherent in coal reserve and resource estimates, such as the accuracy of geophysical data that are used to support mine planning, identify hazards and inform operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess coal reserves and resources or could impact production levels. The over- or underestimation of reserves can have certain impacts on financial performance, such as changes in amortizations that are based on life-of-mine estimates.

Pennsylvania Mining Complex - Material Thermal Reserves

Pennsylvania Mining Complex. The PAMC is located approximately 26 miles southwest of Pittsburgh, near the city of Washington and the borough of Waynesburg, all in Pennsylvania, and consists of three deep longwall mining operations - the Bailey Mine, the Enlow Fork Mine and the Harvey Mine - as well as a centralized preparation plant located at approximately 39°58’23.7” N latitude and 80°24’43.6” W longitude. The Company controls approximately 179,000 acres of mineral and surface rights as a complex collection of owned or leased tracts that range from less than an acre to several hundred acres in size covered by various coal deeds and coal lease agreements. Lease terms generally extend until all the coal is removed from the subject tract. Where applicable, royalty rates typically range from 3% to 8% of the gross sales price of the coal. The Company maintains the right to mine and remove almost all of the Pittsburgh Seam within the PAMC boundaries. As part of the PAMC, the Company controls surface rights to approximately 24,100 acres through fee simple ownership. This includes ownership of the property upon which the surface facilities for mine access, processing,

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storing and shipping are located, as well as approximately 3,500 permitted acres for coarse and fine refuse disposal facilities. Despite a lengthy ownership history dating back to the 1920s with the acquisition of certain coal leases by the Company’s predecessor, commercial operations at the PAMC did not begin until 1984.

The design of the PAMC is optimized to produce large quantities of coal on a cost-efficient basis. The PAMC is able to sustain high production volumes at comparatively low operating costs due to, among other things, its technologically advanced longwall mining systems, logistics infrastructure and safety. All of the PAMC’s mines utilize longwall mining, which is a highly-automated underground mining technique that produces large volumes of coal at lower costs compared to other underground mining methods. The PAMC typically operates 4-5 longwalls with 15-17 continuous mining sections. The full-capacity production of the PAMC is approximately 28.5 million clean tons of coal annually. The central preparation plant is connected via conveyor belts to each of the PAMC’s mines and cleans and processes up to 8,200 raw tons of coal per hour. The PAMC’s on-site logistics infrastructure at the central preparation plant includes a dual-batch train loadout facility capable of loading up to 9,000 clean tons of coal per hour and 19.3 miles of track linked to separate Class I rail lines owned by Norfolk Southern and CSX, which significantly increases the PAMC’s efficiency in meeting its customers’ transportation needs. Sources of electrical power, water, supplies and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments or water wells.

Numerous permits are required by federal and state law for underground mining, coal preparation and related facilities and other incidental activities. Permits generally require that the Company post a performance bond in an amount established by the regulatory program to (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated and (2) assure that all regulation requirements of the permit are fully satisfied.

Bailey Mine. As of December 31, 2025, the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 144.9 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,948 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.65. The Bailey Mine was the first mine developed at the PAMC. Construction of the slope and initial air shaft began in 1982. The slope development reached the coal seam at a depth of approximately 600 feet, and, following development of the slope bottom, commercial coal production began in 1984. Longwall mining production commenced in 1985, and the second longwall was placed into operation in 1987. In 2010, a new slope and overland belt system was commissioned, which allowed a large percentage of the Bailey Mine to be sealed off. For the years ended December 31, 2025, 2024 and 2023, the Bailey Mine produced 11.7 million, 10.8 million and 11.2 million tons of coal, respectively.

Enlow Fork Mine. As of December 31, 2025, the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 228.3 million tons of clean recoverable coal with an average as-received gross heat content of approximately 13,005 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.08. The Enlow Fork Mine is located directly northeast of the Bailey Mine. Initial underground development started from the Bailey Mine while the Enlow Fork slope was being constructed. Once the slope bottom was developed and the slope belt became operational, seals were constructed to separate the two mines. Following development of the slope bottom, commercial coal production began in 1989. Longwall mining production commenced in 1991, and the second longwall came online in 1992. In 2014, a new slope and overland belt system was commissioned and a substantial portion of the Enlow Fork Mine was sealed. For the years ended December 31, 2025, 2024 and 2023, the Enlow Fork Mine produced 10.0 million, 9.2 million and 8.7 million tons of coal, respectively.

Harvey Mine. As of December 31, 2025, the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 155.8 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,938 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 4.17. The Harvey Mine is located directly southeast of the Bailey and Enlow Fork Mines. Similar to the Enlow Fork Mine, the Harvey Mine was developed off of the Bailey Mine’s slope bottom. In order to separate the Harvey Mine from the existing Bailey Mine, seals were built around the original Bailey slope bottom, and the original slope was dedicated solely to the Harvey Mine. This transfer of infrastructure eliminated the need to make significant capital expenditures to develop, among other things, a new slope, airshaft and portal facility at the Harvey Mine. Development of the Harvey Mine began in 2009, and construction of the supporting surface facilities commenced in 2011. Longwall mining production commenced in March 2014. For the years ended December 31, 2025, 2024 and 2023, the Harvey Mine produced 5.6 million, 5.7 million and 6.2 million tons of coal, respectively.

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The following table sets forth additional information regarding the recoverable coal reserves at the Pennsylvania Mining Complex (tons in millions):

Leer Complex - Material Metallurgical Reserves

Leer Complex. The Leer Complex is located on approximately 144,000 acres in Barbour, Taylor and Preston Counties, approximately 25 miles south of Morgantown, West Virginia. Within the complex, there are two active longwall operations, Leer Mine and Leer South Mine, and a third longwall reserve, Leer West. The Leer and Leer South operations run one longwall each and have separate independent preparation plants and train loadout facilities, each serviced by CSX railroad. Both the Leer and Leer South facilities are capable of loading a unit train in less than four hours.

Leer Mine. The Leer Mine is a single longwall operation located in Taylor County, West Virginia, approximately three miles east of the town of Grafton at approximately 39°19’52.62” N latitude and 79°57’48.26” W longitude. As of December 31, 2025, the Leer Mine’s reserves are estimated at approximately 29.4 million tons of High-Vol A metallurgical coal, mining the Lower Kittanning Seam, with an average dry coal product quality of 1.03% sulfur and 8.00% ash. The Company owns roughly 99% of all coal within Leer’s reserves area. Leer’s preparation plant processes up to 1,400 tons of raw coal per hour. For the year ended December 31, 2025, the Leer Mine produced 5.1 million tons of coal.

Leer South Mine. The Leer South Mine is a single longwall operation located in Barbour County, West Virginia, approximately three miles north of the town of Philippi at approximately 39°11’57.57” N latitude and 80°03’07.54” W longitude. As of December 31, 2025, Leer South’s reserves are estimated at approximately 57.0 million tons of High-Vol A metallurgical coal, mining the Lower Kittanning Seam, with an average dry coal product quality of 1.23% sulfur and 8.80% ash. The Company owns approximately 86% of all coal within Leer South’s reserves area, and leases the remaining 14%. Leer South’s preparation plant processes up to 1,600 tons of raw coal per hour. For the year ended December 31, 2025, the Leer South Mine produced 0.4 million tons of coal.

Leer West Mine. The Leer West Mine is a planned single longwall operation located in Taylor County, West Virginia, approximately four miles west of the town of Grafton. As of December 31, 2025, Leer West’s reserves are estimated at approximately 83.8 million tons of High-Vol A metallurgical coal, mining the Lower Kittanning Seam, with an average projected dry coal product quality of 1.18% sulfur and 9.90% ash. The Company owns approximately 96% of all coal within Leer West’s reserves area and leases the remaining 4%. There are no immediate plans to develop Leer West; however, the reserves abut the Leer South Mine, and its southern extent is accessible and may be mined from Leer South.

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The following table sets forth additional information regarding the recoverable coal reserves at the Leer Complex (tons in millions):

Black Thunder Surface Mine - Material Thermal Reserves

Black Thunder Surface Mine. The Black Thunder Surface Mine is located in Campbell County, Wyoming, approximately 11 miles east of the town of Wright at approximately 43°42’07.64” N latitude and 105°17’28.09” W longitude. The Company controls approximately 62,100 contiguous acres of mining rights through 18 state and federal leases. As of December 31, 2025, Black Thunder’s recoverable reserves are estimated at approximately 331.5 million tons. The mine produces sub-bituminous thermal coal via dragline and truck and shovel from the Wyodak and Upper Wyodak Seams in four active pit areas. It employs two train loadout facilities with a total combined loading capacity of 16,000 tons per hour and is serviced by both the Burlington Northern Santa Fe and Union Pacific railroads. For the year ended December 31, 2025, the Black Thunder Mine produced 47.4 million tons of coal.

The following table sets forth additional information regarding the recoverable coal reserves at the Black Thunder Surface Mine (tons in millions):

Itmann Mining Complex - Non-Material Metallurgical Reserves

Itmann No. 5 Mine. The Itmann No. 5 Mine is located in Wyoming County, West Virginia, approximately 2.5 miles northwest of the town of Itmann at approximately 37°35’23.65” N latitude and 81°27’14.43” W longitude. The Company controls approximately 20,200 contiguous acres of mining rights (comprising 270 tracts), by ownership or lease, to the Pocahontas 3 seam (P3) and the Pocahontas 4 seam (P4). The majority (approximately 92%) of the acreage is held under coal leases with lengthy terms that are subject to industry standard royalties.

In 2019, the Company commenced development of the new Itmann No. 5 Mine, including excavation of the box cut to access the P3 seam. The mine accesses the P3 and P4 seams using a box cut drift entrance near an outcrop along Still Run Hollow. As of December 31, 2025, the Itmann No. 5 Mine’s assigned reserve base contained an aggregate of 27.1 million tons of clean recoverable coal, enough to allow for more than 30 years of full-capacity production, based on our current estimates. These reserves contain an approximate average quality on a dry basis of 0.97% sulfur, 7.2% ash and 19.3% volatile matter. Coal from the Itmann No. 5 Mine is currently extracted by underground methods using two continuous miner units in one super section. For the years ended December 31, 2025, 2024 and 2023, the Itmann No. 5 Mine produced 453 thousand, 393 thousand and 316 thousand tons of coal, respectively.

The Itmann preparation plant was constructed in 2022 and began processing coal in late September 2022. Coal is shipped from the Itmann No. 5 Mine via tandem trucks to the 600 raw ton-per-hour processing facility, which is located approximately 2.5 miles west of the mine along WV State Route 10/16. The plant includes clean coal material handling

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systems capable of handling up to 3,500 tons-per-hour of product along with a 3,500 ton-per-hour unit train loadout located on the Guyandotte Class I rail line, which can be served by both Norfolk Southern and CSX. Third-party coal is also trucked into the facility for processing, blending and shipment via rail or truck.

Beckley Mine - Non-Material Metallurgical Reserves

Beckley Mine. The Beckley Mine is located in Raleigh County, West Virginia, approximately one mile south of the town of Eccles at approximately 37°46’04.85” N latitude and 81°15’24.00” W longitude. The Company controls approximately 16,600 contiguous acres of mining rights by lease and ownership to the Pocahontas 3 seam (P3). As of December 31, 2025, Beckley’s recoverable reserves are estimated at approximately 22.6 million tons. The mine produces premium Low-Vol metallurgical coal, and recoverable reserves contain an approximate average quality on a dry basis of 1.00% sulfur, 6.16% ash and 18.0% volatile matter. Coal from the Beckley Mine is currently extracted by underground methods using ten continuous miner units in five super sections. For the year ended December 31, 2025, the Beckley Mine produced 1.2 million tons of coal. Beckley’s preparation plant can process 600 tons per hour. The mine’s rail loadout facility is serviced by the CSX railroad.

Mountain Laurel Mine - Non-Material Metallurgical Reserves

Mountain Laurel Mine. The Mountain Laurel Mine is located in Logan County, West Virginia, approximately two miles south of the town of Sharples at approximately 37°54’17.50” N latitude and 81°47’28.24” W longitude. The Company controls approximately 38,200 contiguous acres of mining rights by lease and ownership to the Alma and No. 2 Gas Seams. As of December 31, 2025, Mountain Laurel’s recoverable reserves are estimated at approximately 16.3 million tons. The mine produces High-Vol A metallurgical coal, and recoverable reserves contain an approximate average quality on a dry basis of 0.91% sulfur, 13.19% ash and 37.5% volatile matter. Coal from the Mountain Laurel Mine is currently extracted by underground methods using eight continuous miner units in three super sections and two conventional sections. For the year ended December 31, 2025, the Mountain Laurel Mine produced 1.2 million tons of coal. Mountain Laurel’s preparation plant can process 1,400 tons per hour, and the mine’s rail loadout facility is serviced by the CSX railroad.

West Elk Mine - Non-Material Thermal Reserves

West Elk Mine. The West Elk Mine is located in Gunnison County, Colorado, approximately one mile east of the town of Somerset at approximately 38°55’35.11” N latitude and 107°26’46.78” W longitude. The Company controls approximately 19,200 contiguous acres of mining rights by lease to the E, C and B Seams. As of December 31, 2025, West Elk’s recoverable reserves are estimated at approximately 31.5 million tons. The mine produces High-Vol thermal coal, and recoverable reserves contain an approximate average quality on an as-received basis of 0.59% sulfur, 10.05% ash and 11,644 Btu. Coal from the West Elk Mine is currently extracted by underground methods using one longwall. For the year ended December 31, 2025, the West Elk Mine produced 3.2 million tons of coal. West Elk typically runs product as run-of-mine, but it also has a preparation plant to partially run product to meet customer specifications. The mine’s rail loadout facility is serviced by the Union Pacific railroad.

Coal Creek Surface Mine - Non-Material Thermal Resources

Coal Creek Surface Mine. The Coal Creek Surface Mine is located in Campbell County, Wyoming approximately 24 miles south of the town of Gillette at approximately 43°58’16.85” N latitude and 105°16’59.19” W longitude. The Company controls approximately 7,400 contiguous acres of mining rights by lease to the R1 and R3 Splits of the Wyodak Seam. As of December 31, 2025, the Coal Creek Surface Mine’s raw, in situ resources are estimated at approximately 124.3 million tons. The mine produces sub-bituminous run-of-mine thermal coal via dragline and truck and shovel from one active pit area. It employs one train loadout facility and is serviced by both the Burlington Northern Santa Fe and Union Pacific railroads. For the year ended December 31, 2025, the Coal Creek Surface Mine produced 1.5 million tons of coal. The mine is in its reclamation phase and is scheduled to cease production by 2030.

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The following table sets forth additional information regarding the non-material recoverable reserves and non-material raw, in situ resources at our other active operations (tons in millions):

Other Properties - Non-Material Resources as of December 31, 2025

The Company also holds other greenfield raw, in situ coal resources located in NAPP, the Central Appalachian Basin (“CAPP”), the Illinois Basin (“ILB”) and the PRB, which are not deemed individually material and had an estimated 3,400.9 million tons of raw, in situ resources. The Company’s estimate includes raw, in situ High-Vol, Mid-Vol or Low-Vol metallurgical coal resources of 608.4 million tons. Additionally, worldwide demand for metallurgical coal allows some of our raw, in situ resources, currently classified as thermal coal but that possess certain qualities, to be sold as metallurgical coal. The extent to which we can sell thermal coal as crossover metallurgical coal depends upon a number of factors, including the quality characteristics of the reserve or resource, the specific quality requirements and constraints of the end-use customer and market conditions, which affect whether customers are compelled to substitute lower-quality crossover coal for higher-quality metallurgical coal in their blends to realize economic benefits.

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The following tables set forth our other non-material, non-operating, raw, in situ coal resources by region (tons in millions):

(a) Certain projects reported on a clean, recoverable ton reserve basis for the year ended December 31, 2024 are now being reported on a raw, in situ resource basis for the year ended December 31, 2025.

(b) Information for the year ended December 31, 2025 includes properties acquired through the Merger.

(c) Information for the year ended December 31, 2024 is reported on a clean, recoverable ton basis.

Title to and the boundaries of the coal properties that we lease or purchase are verified by law firms retained by us at the time we lease or acquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped resources are discovered in the future, control of and the right to mine resources could be adversely affected.

The following table sets forth the total royalty tonnage and the amount of income, net of related expenses, we received from royalty payments for the years ended December 31, 2025, 2024 and 2023.

(a) Excludes advanced mining royalty, overriding royalty and flat fee royalty payments received of $7,957, $746 and $529 during the years ended December 31, 2025, 2024 and 2023, respectively.

Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report, nor is it included in our reported recoverable reserves and resources.

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Production as of December 31, 2025

The following table contains summary information for the Company’s mines:

Table may not sum due to rounding.

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Coal Marketing and Sales

The following table sets forth tons sold and average realized coal revenue per ton sold:

We sell coal produced by our mines and additional coal that we purchase from other producers. During the year ended December 31, 2025, approximately 37% of our coal revenue was from U.S. electric power generators, 56% was from export markets, comprising 8%, 20% and 28% from power generators, industrial and metallurgical customers, respectively, and 7% was from other domestic customers. During the year ended December 31, 2024, approximately 31% of our coal revenue was from U.S. electric power generators, 66% was from export markets, comprising 12%, 35% and 19% from power generators, industrial and metallurgical customers, respectively, and 3% was from other domestic customers. During the year ended December 31, 2023, approximately 27% of our coal revenue was from U.S. electric power generators, 71% was from export markets, comprising 16%, 40% and 15% from power generators, industrial and metallurgical customers, respectively, and 2% was from other domestic customers.

We made sales to approximately 110 customers from our coal operations during the past two years. During the year ended December 31, 2025, no customers comprised over 10% of our total sales. During the year ended December 31, 2024, two customers each comprised over 10% of our total sales, aggregating approximately 22% of our total sales.

Similarly, prior to the Merger, Arch marketed its metallurgical and thermal coal to domestic and foreign steel producers, domestic and foreign electric power generators, and other industrial facilities. For the year ended December 31, 2024, Arch derived approximately 16% of its total coal revenues from sales to its three largest customers.

Coal Contracts and Pricing

We sell coal to an established customer base through opportunities as a result of strong business relationships or through a formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. In the ordinary course of business, we make efforts to renew or extend contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past.

Domestic coal revenue tends to be derived from contracts that typically have a term of one year or longer, and the pricing is typically fixed. Historically, export coal revenue tended to be derived from spot or shorter-term contracts with pricing determined closer to the time of shipment or based on a market index; however, the Company has secured several long-term export contracts with varying pricing arrangements.

The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits. Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of certain force majeure events. Force majeure events include, but are not limited to, unexpected significant geological conditions or natural disasters. Depending on the language in the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to 12 months.

Of our 2025 sales tons, approximately 28% were sold to export markets and 72% were sold to domestic customers. Of our 2025 sales tons, 73% were sold in the electric power generation market, 16% were sold in the industrial market and 11% were sold in the metallurgical market.

The prices we are able to achieve in the domestic thermal market depend on a number of factors, including (i) the supply-demand balance for our products, (ii) prices for other competing sources of energy used for electric power

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generation, such as natural gas, (iii) power prices in the regions we serve, (iv) prices for coals from other basins that compete in these same regions and (v) pricing under our longer-term contracts, which may have been entered into under different market conditions. Natural gas prices, coupled with increased capacity from new natural gas combined-cycle power plants and renewable energy sources, put pressure on power prices and on the demand for coal-fired electric power generation. These factors can affect the prices that we are able to achieve in the domestic thermal markets.

Similarly, imbalances in global supply and demand for energy fuels can cause substantial variability in pricing in the export markets we serve, which include industrial, metallurgical and electric power generation applications. The prices we are able to achieve in these export markets depend on a number of factors, including (i) the supply-demand balance of seaborne thermal coal, specifically high calorific value coals, (ii) the supply-demand balance of seaborne metallurgical coal, (iii) prices for other competing sources of energy used in certain industrial applications, such as petroleum coke and metallurgical coal, (iv) prices for other competing sources of energy used for electric power generation, such as natural gas, (v) prices for other export coals that compete in these same markets and (vi) pricing under our longer-term contracts, which may have been entered into under different market conditions.

Distribution

Coal is transported from the Company’s mining operations to customers predominantly by railroad cars and ocean vessels. Most customers coordinate their own transportation. For the remaining customers, our sales and logistics specialists negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies.

Seasonality

Our business has historically experienced limited variability in its results due to the effect of seasonal changes. Demand for coal-fired electric power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for our thermal coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to transport coal with our overland conveyor systems and by rail.

Competition

The coal industry is highly competitive, with numerous producers selling into all markets that use coal. There are numerous large and small producers in all coal-producing basins of the U.S., and we compete with many of these producers, including those who export coal abroad. Potential changes to international trade agreements, trade concessions and tariffs or other political and economic arrangements may benefit coal producers operating in countries other than the U.S. We may be adversely impacted on the basis of price or other factors compared to companies that in the future may benefit from favorable foreign trade policies or other arrangements. In addition, coal is sold internationally in U.S. dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our international competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our international customers’ local currencies, those competitors may be able to offer lower prices for coal to our customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of international coal consumers and the domestic electric power generation industry. These coal consumption patterns are influenced by many factors that are beyond our control, including demand for cement and steel manufacturing, demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures, government regulation, technological developments and the location, quality, price and availability of competing fuel sources.

Indirect competition for sales of thermal coal from natural gas-fired power plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired power plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly older, less efficient coal-fired electric power generators. Federal and state mandates for increased use of electricity derived from renewable energy sources can also affect demand for our coal. Such mandates, combined with falling costs for wind and solar energy technologies and other incentives to use renewable energy sources, such as tax credits, have made alternative fuel sources more competitive with coal. Additionally, competition for production of steel from non-coal sources, including electric arc

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furnaces or other alternative processes, or competition for production of cement from other sources, including petroleum coke, may limit demand for our product.

Human Capital Management

As of December 31, 2025, Core and its subsidiaries had 4,850 employees, of which 39 Core Marine Terminal employees were represented by a collective bargaining agreement. We believe our efforts in managing our workforce have been effective, evidenced by a strong culture and a good relationship between the Company and our employees.

Health and Safety. The success of our business is fundamentally connected to the well-being of our people. Accordingly, we are committed to the health, safety and wellness of our employees. We provide our employees and their families with access to health and welfare programs, including benefits that support their physical and mental health by providing tools and resources to help them improve or maintain their health status.

Talent. Through our long operating history and experience with technological innovation, we appreciate the importance of retention, growth and development of our employees. Our approach to talent is to both develop talent from within and supplement with external hires. We believe this method has yielded loyalty and commitment in our employee base, which in turn grows our business, while at the same time, adding new employees and external ideas supports a continuous improvement mindset and contributes to our goals of having a diverse and inclusive workforce. We believe that having approximately 39% of the Company’s workforce with at least ten years of company service, coupled with our average voluntary retention rate of 87% as of December 31, 2025 reflects the engagement of our employees.

Total Rewards. Our employees are critical to the success of our Company. As such, we offer market-competitive total rewards programs for our employees in order to attract and retain superior talent. In addition to competitive base wages, the Company has additional programs, which include bonus opportunities, a Company-matched 401(k) plan, healthcare and insurance benefits, health savings spending accounts, paid time off, family leave, flexible work schedules, employee wellness programs and employee assistance programs.

Employee Development. The Company provides its employees with tools and development resources to enhance their skills and careers at the Company, including (i) encouraging employees to discuss their professional development and identify interests or possible cross-training areas during annual performance reviews with their supervisors, (ii) providing a tuition aid program for educational pursuits related to present work or possible future positions, (iii) providing talent review and succession planning and (iv) providing opportunities for on-the-job growth through stretch assignments or temporary projects outside of an employee’s typical responsibilities.

Laws and Regulations

Overview

Our coal mining operations are subject to various federal, state and local environmental, health and safety regulations. Regulations relating to our operations require us to obtain permits and other licenses; reclaim and restore our properties after mining operations have been completed; store, transport and dispose of materials used or generated by our operations; manage surface subsidence from underground mining; control water and air emissions; protect wetlands and endangered plants and wildlife and ensure employee health and safety. Furthermore, the electric power generation industry, steel production industry and other users of our coal are subject to extensive regulation regarding the environmental impact of their activities, which could affect demand for our coal.

We seek to conduct our operations in compliance with applicable laws and regulations. However, from time to time, violations occur during operations, and we cannot assure that we have been or will be at all times in compliance with such laws and regulations. Compliance with these laws has substantially increased the cost of coal mining, and the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our coal mining operations or our customers’ ability to use our coal and may require us or our customers to significantly modify operations or incur substantial costs. Additionally, these laws are subject to revision and may become increasingly stringent.

In addition, independent of the regulatory process, presidential administrations could issue executive orders or other presidential directives having the force of law that could immediately impact our business or our customers’ businesses. As part of a broad deregulatory strategy since taking office, President Trump has issued several executive orders aiming to suspend, revise or rescind regulatory actions from the prior administration. For example, on January 20, 2025, President Trump issued Executive Order 14154 “Unleashing American Energy” that directs all federal agency heads to identify any agency actions that “impose an undue burden on the identification, development, or use of domestic energy resources.” On March 12, 2025, the U.S. Environmental Protection Agency (“EPA”) announced its intention to take a variety of deregulatory actions to implement the administration’s environmental and energy policies (the “Rollback Plan,” discussed

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below). The ultimate effect of these actions may not be predictable, as various associated regulations are still in development or subject to public notice, extensive comment or judicial review.

The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we or our customers’ business operations are subject and for which compliance may have a material adverse effect on our business, results of operations, financial condition or demand for our coal. See Item 1A. “Risk Factors” included in this Report for additional discussion regarding laws and regulations affecting our business, operations and industry.

Environmental Laws

Clean Air Act. The U.S. federal Clean Air Act (“CAA”) and corresponding state and local laws and regulations affect multiple aspects of our business, both directly and indirectly. The CAA directly impacts our coal mining and coal export operations through permitting and emission control requirements for the construction, operation, modification or expansion of certain facilities, including our mines, coal preparation plants and export terminal operations. In certain cases, if emissions have the potential to exceed major source thresholds established by the EPA, an operating permit under Title V of the CAA is required to operate. To comply with emissions limits or other compliance requirements under Title V, we may be required to install capital-intensive pollution control devices, incur expenses associated with the purchase of emissions credits or curtail production. Such requirements could have a material adverse effect on our business, financial condition and results of operations.

Indirectly, the CAA affects the U.S. coal industry by extensively regulating the air emissions of coal-fired power plants or other industrial facilities operated by our customers. Coal impurities are released into the air when coal is burned, and the CAA regulates specific emissions, such as sulfur dioxide, nitrogen oxides, particulate matter, mercury and other substances, produced during that process. In addition, CAA programs such as Maximum Achievable Control Technology (“MACT”) emission limits for Hazardous Air Pollutants (“HAPs”), the Regional Haze Program, New Source Review permitting requirements and other federal rulemakings may directly or indirectly affect our operations. Such regulations restricting emissions from coal-fired power plants or other industrial facilities could increase the costs of operating and affect demand for coal as a fuel source, therefore potentially affecting the volume of our sales. Moreover, additional environmental regulations increase the likelihood that existing coal-fired power plants will be decommissioned or replaced with alternative sources of fuel and reduce the likelihood that new coal-fired power plants will be built in the future.

Mercury and Air Toxics Standards Rule. In 2012, the EPA promulgated a rule establishing National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for new and existing coal- and oil-fired electric generating units (“EGUs”). The EPA’s 2012 Mercury and Air Toxics Standards rule (“2012 MATS Rule”) imposed MACT emissions limitations on Hazardous Air Pollutants, such as mercury, acid gas HAPs, HAP metals and organic HAPs, for applicable facilities. Following multiple regulatory actions, in May 2024, the EPA finalized amendments to the NESHAPs for coal- and oil-fired EGUs, further restricting emissions limitations and establishing a compliance date of July 8, 2027. In April 2025, President Trump signed a proclamation exempting certain sources from compliance with the 2024 MATS amendments for a period of 2 years. In June 2025, the EPA proposed a rule to repeal the 2024 MATS amendments, reverting certain emission standards and compliance requirements to those established in the 2012 MATS Rule.

National Ambient Air Quality Standards. The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for six “criteria pollutants” (including particulate matter (“PM”), nitrogen oxides (“NOx”), ozone, sulfur dioxide (“SO2”), lead and carbon monoxide) considered harmful to public health and the environment. The EPA must review these standards every five years. Areas that are not in compliance with the NAAQS are considered “non-attainment areas.” The designation of new non-attainment areas could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans (“SIPs”) that require emission source identification and emission reduction plans, which may include significant investment in emissions control technologies associated with our or our customers’ operations. Related to the PM NAAQS, the EPA published a final rule lowering the standard for fine particulate matter (“PM2.5”), which became effective in May 2024 and is subject to ongoing litigation in the D.C. Circuit Court of Appeals. As part of the Rollback Plan, the EPA announced it would reconsider the May 2024 PM2.5 rule, and in November 2025, the EPA filed a motion requesting the D.C. Circuit to vacate the rule. Review proceedings for NOx and ozone have also been announced and are in preliminary phases.

Cross State Air Pollution Rule (“CSAPR”) and Good Neighbor Plans. The CSAPR was finalized in 2011 to satisfy the “good neighbor” provisions of the CAA, which require upwind states to eliminate their contributions to downwind states’ non-attainment of the NAAQS. In February 2023, the EPA issued its final disapproval of SIPs submitted by 21 states to address interstate air pollution in furtherance of attaining the 2015 Ozone NAAQS. The EPA’s SIP disapprovals were challenged by several states in the respective jurisdictions’ federal court of appeals, and litigation is ongoing in most cases.

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Following the SIP disapprovals, in March 2023, the EPA published the Good Neighbor Plan Federal Implementation Plan (“FIP”) for the 2015 Ozone NAAQS. The rule relies, in part, on a NOx allowance trading program and requires operation of existing, and installation of new, emissions control technologies for EGUs and other industrial sources. Upwind states challenged the FIP, and the Supreme Court issued a decision temporarily blocking its implementation while litigation is ongoing. In November 2024, the EPA issued an interim final rule that imposed a nationwide administrative stay on the Good Neighbor Rule. Separately, in June 2025, the Supreme Court issued its decision that the proper venue for challenging the EPA’s denial of SIPs is the associated regional circuit court. As part of the Rollback Plan, the EPA announced its intention to reconsider the Good Neighbor Plan.

Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units under CAA Sections 111(d) and 111(b). In May 2024, the EPA published a suite of final rulemakings under CAA sections 111(d) and 111(b) establishing the National Pollutant Discharge Permit System for greenhouse gas (“GHG”) emissions from existing and new fossil fuel-fired EGUs, respectively. The final rule, referred to as the “Clean Power Plan 2.0,” replaced the Affordable Clean Energy rule, which was vacated and remanded to the EPA by the D.C. Circuit in 2021.

For existing coal-fired EGUs in operation on or after January 1, 2039, the rule requires EGUs to be equipped with Carbon Capture and Storage (“CCS”) with 90% capture on or before January 1, 2032. For coal-fired EGUs that will cease operations by January 1, 2039, the rule requires compliance with a numeric emission rate based on 40% co-firing natural gas with coal on or before January 1, 2030. Coal-fired EGUs planning to permanently cease operations before January 1, 2032 would not be subject to emissions guidelines.

To achieve compliance, our customers could be required to incur substantial capital investment and increased operating costs. Alternatively, EGU owners and operators may accelerate the closure of existing power plants or agree to curtail their use. The suite of rules was challenged and is subject to ongoing litigation before the D.C. Circuit. In October 2024, the Supreme Court denied emergency applications to stay the rule while litigation is ongoing. In June 2025, the EPA published a proposed rulemaking repealing GHG emissions standards for fossil fuel-fired EGUs established by the Clean Power Plan 2.0.

Global Climate Change

Our customers’ consumption of the coal we produce results in the emission of GHGs, particularly carbon dioxide (“CO2”). To date in the U.S., no legislation to comprehensively regulate global climate issues and GHG emissions has been signed into law. In August 2025, the EPA published a proposed rulemaking to rescind findings published in 2009 that concluded GHG emissions pose an endangerment to public health and the environment. If finalized, the EPA would lack statutory authority under Section 202(a) of the Clean Air Act to prescribe standards for GHG emissions.

During coal mining operations, GHG emissions are primarily tied to combustion of fuel from mining equipment used in production, consumption of electricity and the ventilation of methane from our coal mines to promote a safe working environment for our miners underground. Since 2011, the EPA has required active underground coal mines and certain support facilities exceeding a minimum GHG emission threshold, including our operations, to report annual emissions to the EPA under the GHG Mandatory Reporting Rule (“MRR”). In September 2025, the EPA published a proposed rule to permanently repeal the MRR for certain source categories, including underground coal mines.

Separately, federal, state and international jurisdictions have proposed or enacted laws and regulations requiring companies to disclose climate-related risks, certain climate-related financial metrics, an accounting of direct and indirect GHG emissions and details of climate change targets and goals. For example, on March 6, 2024, the Securities and Exchange Commission (“SEC”) adopted final rules requiring registrants to disclose certain climate-related information in their registration statements and annual reports. The rule has been stayed pending litigation; however, the Eighth Circuit has held the litigation in abeyance pending the SEC’s defense of the rule or undertaking of a formal rulemaking to withdraw the rule. Similar rules, such as those adopted in California and the European Union, impose reporting obligations related to climate-related metrics and impacts. Calculation of some GHG emissions can involve uncertainty and lack precision because of the absence of reliable inputs or methods to perform such calculations, which could give rise to litigation risk. While the California rules are subject to litigation, regulators are continuing to prepare for implementation; as such, we are unsure of the ultimate fate of these rules or the potential effects on the Company.

In the absence of sweeping federal legislation on GHG emissions in the U.S., a number of states, governors, mayors and businesses have committed to broad goals for GHG reductions or requirements to deploy carbon-free or renewable sources of electricity. Such goals include those announced by multiple domestic utilities, including some of our customers, pledging to substantially reduce or to achieve net zero GHG emissions or to increase generating capacity from renewable sources. These goals could ultimately affect the demand and prices for our coal as these customers seek to achieve such goals over time.

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In addition, certain states have enacted requirements for utilities to provide a minimum percentage of power from renewable sources or mandatory cap-and-trade initiatives, seeking to limit CO2 emissions annually, in order to achieve a prescribed long-term emissions reduction target. In cap-and-trade scenarios, electric power generators or other GHG emitters are required to purchase allowances, available through auction or a secondary market, that are equal to one ton of CO2 emissions, thereby increasing the cost of electric power generation and incentivizing the power generator to limit their CO2 emissions by combusting fewer fossil fuels, including coal.

Taking a different approach, in 2024, the states of New York and Vermont passed legislation requiring fossil fuel companies to make contributions to state managed “climate superfunds” established to finance the cost of repairs and upgrades to public infrastructure in response to severe weather and other climatic events. Analogous “climate superfund” legislation has also been proposed in multiple states, including California, Connecticut, Hawaii, Maryland, Massachusetts, New Jersey, Oregon, Rhode Island and Virginia. Modeled after the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the climate superfunds retroactively impose strict liabilities on fossil fuel companies determined to be responsible for GHG emissions over defined time periods and quantitative thresholds, potentially exposing businesses to substantial financial liabilities associated with historical pollution. Similarly in 2024, legislation proposing to establish the “Fossil Fuel Transportation Fee and Mitigation Fund” was introduced in the Maryland House of Delegates. The legislation would impose a fee of 30 cents per mmBtu on companies transporting fossil fuels in Maryland and would establish the “Fossil Fuel Mitigation Fund” to support activities that reduce GHG emissions in the state. Any regulations or legislation imposing fees on the production, transportation or use of the coal we produce, or seeking damages or abatement for climate change impacts could and may have a material adverse effect on our business, financial condition and results of operations.

At both the federal and state levels, environmental organizations, third parties and regulators have challenged permitting actions associated with new fossil fuel infrastructure, power plants, pipelines and shipping terminals, citing GHG emissions or the failure to account for their climate change impacts. Challenges such as these could result in litigation, limit operational expansion efforts, create permitting delays or restrict coal shipments, any of which could materially impact production, cash flows and results of operations.

Foreign governments, including the European Union and member countries, have adopted regulations governing GHG emissions. Independent of regulation, the United Nations Framework Convention on Climate Change (“UNFCCC”) seeks to establish GHG emission reduction requirements for developed countries. The UNFCCC’s governing body, the Conference of the Parties (“COP”), meets annually to implement and refine a framework for the international Paris Agreement, a voluntary commitment to limit or reduce GHG emissions in order to limit global warming below 2 degrees Celsius from temperatures in the pre-industrial era. The U.S. has withdrawn from the Paris Agreement and, on January 7, 2026, President Trump issued an executive order calling for the withdrawal of the U.S. from the UNFCCC. However, the ultimate effect of these withdrawals is uncertain as it may incite various state and other policymakers to introduce stricter requirements.

Federal, state and international GHG and climate change initiatives, associated regulations or other voluntary commitments to reduce GHG emissions have and are expected to continue to result in (i) the decreased utilization or accelerated closure of existing coal-fired EGUs, (ii) the increased utilization of alternative fuels or generating systems, (iii) a reduction or elimination of new coal-fired power plant construction in certain countries or (iv) the advancement of technologies aimed toward replacing or minimizing the use of coal in industrial or metallurgical processes. Such initiatives and regulations could further reduce demand or prices for our coal in both domestic and international markets, could adversely affect our ability to produce coal and to develop our reserves, could reduce the value of our coal and coal reserves and may have a material adverse effect on our business, financial condition and results of operations.

Clean Water Act

The U.S. federal Clean Water Act (“CWA”) and corresponding state laws affect our coal and export terminal operations by regulating discharges into certain waters of the United States (“WOTUS”). CWA permits, issued either by the EPA or an analogous state agency, typically require regular monitoring and compliance with limitations on defined pollutants and impose related reporting requirements. Specific to the Company’s operations, CWA permits and corresponding state laws at times include, among other requirements, (i) treatment of discharges from coal mining properties and (ii) mandates to dispose of wastes at approved disposal facilities. Additional CWA requirements that could directly or indirectly affect our operations are summarized below.

Dredge and Fill Permits Under CWA Sections 401 and 404. In order to obtain a permit for certain coal mining activities, such as the construction of coal refuse areas and slurry impoundments that may result in impacts to waters of the U.S., an operator may need to obtain a permit for the discharge of fill material from the Army Corps of Engineers (“ACOE”) under Section 404 of the CWA. For specific categories of activities determined to have minimal effects, the Company may be required to comply with Nationwide Permits from the ACOE. In addition, through the CWA Section 401

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Certification Program, state regulators have approval authority over federal permits authorizing activities that could impact state water quality and must certify that the activity will comply with water quality standards or other applicable requirements. In 2023, the EPA issued the CWA Section 401 Water Quality Certification Improvement Rule (the “2023 Rule”) which broadened states’ review of water quality impacts. The 2023 Rule remains in effect and is subject to litigation in the U.S. District Court for the Western District of Louisiana. In January 2026, the EPA announced a proposed rule revising the 2023 Rule, to narrow the scope of certification and standardize certain associated procedures.

Definition of Waters of the United States. The scope of regulated waters has been subject to uncertainty, with the EPA and the ACOE finalizing multiple rulemakings to define WOTUS since 2015. Ultimately, in 2023, the Supreme Court issued its decision in Sackett v. EPA, which narrowed federal jurisdiction over wetlands under the CWA to those with a continuous surface connection to bodies that are waters of the U.S. In response, the EPA and the ACOE issued a final rule revising the definition of WOTUS to conform with the Sackett decision; however, the rule was only implemented in 24 states, the District of Columbia and the U.S. Territories due to ongoing litigation. In November 2025, the Trump administration proposed a rule seeking to narrow the definition of WOTUS to “relatively permanent” waters with a “continuous surface connection.”

Water Discharge Permits. The Company must obtain permits issued pursuant to the National Pollutant Discharge Elimination System (“NPDES”) from the appropriate federal or state permitting authority under Section 402 of the CWA. These permits establish effluent limitations for discharges to receiving waters that are protective of water quality standards. For discharges to receiving waters that are classified as either high-quality or impaired, stringent restrictions are established to ensure anti-degradation and compliance with water quality standards. Permitting such discharges under NPDES could increase the cost, time and difficulty of complying with permit requirements and may warrant costly treatment that could affect our operations.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. The 2015 Effluent Limitations Guidelines and Standards (“ELG”) rule established the first federal limits on the levels of toxic metals in various power plant wastewater discharges and set zero-discharge requirements for certain waste streams. Revisions to the 2015 ELG rule were published in October 2020 (“Reconsideration Rule”) and established a voluntary incentive program which provides power plants until December 31, 2028 to (i) retire or (ii) implement changes required to achieve compliance with stringent effluent limits and standards. In May 2024, the EPA published the final Supplemental ELG Rule, further restricting the ELGs established by the Reconsideration Rule, incorporating limitations for additional waste streams and establishing procedural requirements for affected facilities to demonstrate permanent cessation of coal combustion or permanent retirement. The 2024 Supplemental ELG Rule was challenged in the Eighth Circuit Court of Appeals. Most recently, on December 31, 2025, the EPA published a final rule extending the deadline to December 31, 2031 for coal-fired power plants electing to permanently cease coal combustion by 2034. It also extended the deadlines to achieve compliance for certain waste streams by five years from December 31, 2029 to December 31, 2034. The final rule provides additional flexibility to prevent the premature retirement of coal-fired EGUs.

Other Environmental Laws and Regulations

Surface Mining Control and Reclamation Act. The U.S. federal Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum extraction, environmental, reclamation and closure standards for mining activities. While SMCRA is a comprehensive statute, it does not supersede other major statutes, such as the CAA, CWA, Endangered Species Act and other statutes discussed herein. To facilitate mining activities, operators must obtain SMCRA permits and permit renewals from the U.S. Office of Surface Mining or the applicable state agency. The timing of SMCRA permit issuance is largely at the discretion of the regulatory authorities and is often related to the size and complexity of the operation for which approval is sought. In addition, numerous other permits from applicable federal, state or local authorities are required to conduct mining operations. Timing of permit issuance can also be influenced by public engagement in the permitting process, such as through comment, hearings or legal interventions, which could affect our operations. Permits can also be delayed, refused or revoked if any entity under common ownership or control has unabated permit violations, including the mining and compliance history of officers, directors and principal owners of the entity seeking permit approval. Under the laws applicable to our operations, substantial fines and penalties, including suspension or revocation of permits, and in severe cases, criminal sanctions, may be imposed for failure to comply.

Under federal and state laws, including SMCRA, we are required to obtain surety bonds or other acceptable security to secure payment of our long-term obligations, including mine closure and reclamation, mine water treatment, federal and state workers’ compensation costs, coal leases or other miscellaneous obligations. Surety bonds are typically renewable on a yearly basis, and it is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral. Over the past few years, the surety markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and fewer providers willing to underwrite policies and surety bonds. Terms have become generally unfavorable, including increases in the amount of collateral required to secure surety bonds. However, more recently, we have seen insurance rates and collateral requirements stabilize and even decrease on certain

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lines of coverage, as new insurance carriers have entered the market, although there is no assurance that this stabilization or decrease will be sustained or continued. Any failure to maintain, or our inability to acquire, surety bonds required by federal and state laws or the related collateral required by bond issuers could have a material adverse effect on our ability to produce coal, adversely affecting our business, financial condition, liquidity, results of operations and cash flows. As of December 31, 2025, we posted an aggregated $859 million in surety bonds for mine closure purposes, as well as approximately $228 million in surety bonds and letters of credit to secure other obligations including workers compensation, black lung benefits, coal leases and other obligations.

Additionally, in October 2024, the Company and the Pennsylvania Department of Environmental Protection (“PADEP”) finalized agreements to form a Global Water Treatment Trust Fund, providing an approved alternative financial assurance mechanism for 22 legacy mine water treatment systems in Pennsylvania. The Company intends to make annual contributions of $2 million until the cash balance of the fund equals 100% of the present value of future operation, maintenance and recapitalization costs for the treatment systems, currently estimated to be $74.8 million. As the cash balance of the fund grows, surety bonds associated with the treatment systems will be adjusted or released by the PADEP, thereby reducing our exposure to surety bonds and related collateral requirements. Through December 31, 2025, the Company has contributed $14.1 million to the fund, and the PADEP has approved bond reductions totaling $66.3 million.

Separately, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund, which is used to restore mine lands mined, closed or abandoned before SMCRA’s adoption in 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The current fees of $0.096 per ton and $0.224 per ton for underground and surface-mined coal, respectively, became effective in October 2021. We recognized expense related to Abandoned Mine Reclamation Fund fees of $14.5 million for the year ended December 31, 2025.

Endangered Species Act. The U.S. federal Endangered Species Act (“ESA”) and other related federal and state statutes protect species that have been classified as endangered, threatened with possible extinction or other protective designations. A number of species native to our operating areas are protected under the ESA or other related laws and regulations. Protection of these species could prohibit or delay authorization of mining activities or may place additional restrictions on our operations related to timbering, construction, vegetation or water discharges. In May 2024, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service (collectively, the “Services”) promulgated final regulations related to procedures for listing threatened and endangered species and agency consultation. In November 2025, the Services proposed four rules to revise rules finalized under the previous administration. Imposition of more stringent or protective measures, or designation of additional critical habitat areas, could expose our operations to additional requirements, increased operating costs or delayed approval timeframes.

Comprehensive Environmental Response, Compensation, and Liability Act. The CERCLA imposes remediation requirements related to actual or threatened releases of hazardous substances into the environment. Under CERCLA or related state laws, joint and several liability may be imposed on generators of hazardous waste, site owners and certain previous owners, waste transporters or others regardless of fault associated with the original disposal activity. Although the EPA excludes most wastes generated during coal mining and processing from hazardous waste laws, such wastes may contain hazardous substances that are governed by CERCLA if released into the environment. Our current operations, operations of our predecessors or facilities to which we have sent waste materials could be subject to liability under CERCLA.

Resource Conservation and Recovery Act. The U.S. federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations affect coal mining by imposing requirements for the treatment, storage, transportation and disposal of certain wastes. Certain waste streams created throughout the mining process, such as coal refuse and coal cleaning wastes, are excluded from the regulatory definition of hazardous waste. Further, coal operations authorized under SMCRA are exempt from RCRA permitting requirements. Other solid, residual or hazardous waste streams generated across our operating footprint are subject to state specific regulations and designations. Waste classification, reporting and management requirements vary by state and include measures such as waste classification, reporting and handling, as well as requirements to eliminate or reduce certain waste streams, which could increase our costs, create compliance risk or expose us to long term liability.

Coal Combustion Residuals. Byproducts of coal combustion, or coal combustion residuals (“CCR”), are regulated under RCRA. In April 2015, the EPA published regulations for the disposal of CCR and classified CCR as “non-hazardous” waste. Since 2015, the EPA has made subsequent revisions to CCR requirements, including a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closures between 2021 and 2028, depending on site-specific circumstances. In December 2025, the EPA announced a proposed rule to extend the closure deadline for certain CCR surface impoundments by three years until October 2031. Due to the combined effect of the Trump administration’s rollback of the CCR and ELG regulations discussed above, the retirement date for certain coal-burning power plants could be extended and may positively impact the demand for our coal.

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National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies to complete certain assessments of environmental impacts of certain proposed “major federal actions,” which includes various permitting decisions. NEPA analysis can be time-consuming and require additional compliance costs. Additionally, various environmental activists have historically used NEPA to challenge and stall projects they oppose, which could adversely impact our operations. While there have been various proposals to revise the scope of NEPA or limit associated reviews, we are unsure whether such proposals will be adopted or of their ultimate impact on our operations.

Other Environmental Regulations. We are required to comply with other federal, state and local environmental laws in addition to those discussed above. These laws include, for example, the Safe Drinking Water Act, the Emergency Planning and Community Right to Know Act, the Toxic Release Inventory and the rules governing the use and storage of explosives regulated by the U.S. Bureau of Alcohol, Tobacco and Firearms and the Department of Homeland Security. We are also subject to state specific laws, regulations and guidelines that impose strict compliance and operating requirements. For example, where we are required to plug oil and natural gas wells to facilitate underground mining activities, we must comply with laws such as the Pennsylvania Oil and Gas Act, the Pennsylvania Coal and Gas Resource Coordination Act and other related regulatory requirements. Compliance with these or other state specific requirements across our operations could increase costs or impact production, thereby having a material adverse effect on our business, financial condition and results of operations.

Health and Safety Laws

Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined-out areas and engage in additional training. We have also experienced more aggressive inspection protocols, and with new regulations, the volume of civil penalties has increased. Recent actions taken by federal and state governments include requiring:

•the caching of additional supplies of self-contained self-rescuer devices underground;

•the purchase and installation of electronic communication and personal tracking devices underground;

•the purchase and installation of proximity detection devices on continuous miner machines;

•the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;

•the purchase of new fire-resistant conveyor belting underground;

•additional training and testing that creates the need to hire additional employees;

•more stringent rock dusting requirements; and

•the purchase of personal dust monitors for collecting respirable dust samples from certain miners.

In September 2015, the Mine Safety and Health Administration (“MSHA”) published proposed rules for underground coal mining operations concerning proximity detection systems for coal hauling machines and scoops. The rulemaking record for this proposed rule was closed in December 2016, but in January 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. MSHA has not issued a final rule regarding these proposed rules.

The final rule for respirable crystalline silica took effect on June 17, 2024. This final rule establishes a uniform permissible exposure limit (“PEL”) for respirable crystalline silica of 50 micrograms per cubic meter of air (µg/m³) over a full shift, calculated as an 8-hour time-weighted average (“TWA”) for all miners and requires operators to continue to sample if the results are above the action level of 25 µg/m³, but below the PEL within three months of the previous sample. The previous exposure limit for respirable crystalline silica during a coal miner’s shift was 100 µg/m³, reported as an equivalent full shift TWA concentration as measured by the Mining Research Establishment instrument. Mine operators are required to use laboratories accredited to ISO/IEC 17025 to analyze samples for respirable crystalline silica.

On November 26, 2025, MSHA announced it plans to “engage in limited rulemaking to reconsider and seek comments on portions of the Silica Rule.” The U.S. Court of Appeals for the Eighth Circuit required MSHA to provide an update on its rulemaking efforts by February 2, 2026. Ongoing litigation may continue the stay of the rule’s implementation for an unknown period of time.

Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:

•current and former coal miners totally disabled from black lung disease;

•certain survivors of miners who have died from black lung disease; and

•a trust fund established by the U.S. Department of the Treasury known as the Black Lung Disability Trust Fund (the “trust fund”) for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s

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last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of coal, at a rate of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The Company recognized expense related to the Black Lung Excise Tax of $40.8 million, $11.0 million and $10.9 million for the years ended December 31, 2025, 2024 and 2023, respectively.

In December 2021, the U.S. Government Accountability Office (“GAO”) published a report entitled “Black Lung Benefits Program: Continued Inaction on Coal Operator Self-Insurance Increases Financial Risk to Trust Fund.” This report notes that the U.S. Department of Labor (“DOL”) took certain steps to improve its oversight of self-insured coal mine operators, but these efforts were complicated by the COVID-19 pandemic. The GAO states in the report that the DOL has not taken necessary action to prevent additional benefit liabilities from being transferred to the trust fund and recommends that the DOL act on recommendations made in 2020. In January 2023, the DOL’s Office of Workers’ Compensation Programs (“OWCP”) issued a Notice of Proposed Rulemaking to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts and announced that it plans to solicit public comments for that proposal. A change in requirements for security posted for coal operator self-insurance could result in the Company being required to post additional security for its obligations.

In December 2024, the OWCP issued a final rule revising the regulations under the Black Lung Benefits Act related to self-insurance by coal mine operators. Under the new standard, self-insured coal mine operators are required to post additional security for the Black Lung benefit liabilities. The final rule requires a security amount equal to 100% of a self-insured operator’s projected black lung liabilities. The rule became effective on January 13, 2025, and operators were required to remit the increased security amount within one year. The final rule, including any assessments, is subject to appeal. In February 2025, the Company received letters from the OWCP that additional guidance regarding the final rule will be provided at a future date.

The Patient Protection and Affordable Care Act (“PPACA”) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner’s death. The changes have increased the cost to us of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are also liable under various state statutes for our portion of black lung claims.

Ownership of Coal Rights

The Company acquires ownership or leasehold rights to coal properties prior to conducting operations on those properties. As is customary in the coal industry, we initially conduct a summary review of the title to coal rights that are not in our development plans but which we believe we control at the time of acquisition or as part of a review of our land records to determine control of coal rights. Prior to the commencement of development operations on coal properties, we conduct an additional title examination and perform curative work with respect to significant defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any title defects. We have completed title work on substantially all of our coal producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.

Available Information

We maintain a website at www.corenaturalresources.com. We will make available, free of charge, on this website our future annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the SEC, and are also available on the SEC’s website, www.sec.gov. We also use our website to publish information which may be important to investors, such as presentations to analysts.