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FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2025

For the transition period from _______to _______

Commission file number: 001-38147

275 Technology Drive Suite 101

Canonsburg, PA 15317-9565

(724) 416-8300

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☒ No ☐

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

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

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

The aggregate value of common stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $3,514,239,816 as of June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, based on the reported closing price of the common stock as reported on The New York Stock Exchange on such date.

The number of shares outstanding of the registrant’s common stock as of January 30, 2026 was 50,979,544 shares.

Portions of Core Natural Resources, Inc.’s Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed within 120 days of the end of the registrant’s fiscal year are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.

On January 14, 2025, CONSOL Energy Inc., a Delaware corporation, completed its previously announced all-stock merger of equals transaction (the “Merger”) with Arch Resources, Inc., a Delaware corporation (“Arch”), pursuant to that certain Agreement and Plan of Merger, dated as of August 20, 2024 (the “Merger Agreement”), by and among CONSOL Energy Inc., Mountain Range Merger Sub Inc., a Delaware corporation and wholly-owned subsidiary of CONSOL Energy Inc. (“Merger Sub”), and Arch. Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Arch, with Arch continuing as the surviving corporation and as a wholly-owned subsidiary of the Company. 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.

•“Core Natural Resources,” “Core,” “we,” “our,” “us,” “our Company” and “the Company” refer to Core Natural Resources, Inc. (formerly known as CONSOL Energy Inc. before the effective time of the Merger) and its subsidiaries;

•“Arch” refers to Arch Resources, Inc., a Delaware corporation and a wholly-owned subsidiary of the Company following the Merger;

•“Beckley” refers to the Company’s Low-Vol metallurgical mining complex located in Raleigh County, West Virginia;

•“Black Thunder” refers to the Company’s sub-bituminous thermal surface mining complex located in Campbell County, Wyoming;

•“Btu” refers to one British thermal unit;

•“Coal Creek” refers to the Company’s sub-bituminous thermal surface mining complex located in Campbell County, Wyoming;

•“coal reserves” refer to the Company’s proven and probable coal reserves as defined by Section 1300 et. seq. of Regulation S-K that could be economically mineable, after taking into account modifying factors, including mining recovery and preparation plant yield;

•“Core Marine Terminal” refers to the Company’s terminal operations located in the Port of Baltimore, Maryland;

•“Dominion Terminal” refers to the ground storage-to-vessel coal transloading facility in Newport News, Virginia operated by DTA;

•“DTA” refers to Dominion Terminal Associates LLP, a limited liability partnership, in which the Company owns a 35% interest;

•“former parent” refers to CNX Resources Corporation and its consolidated subsidiaries;

•“Greenfield Reserves and Resources” refer to those undeveloped reserves and resources owned by the Company in the Northern Appalachian, Central Appalachian, Illinois and Powder River basins that are not associated with active mining complexes;

•“Itmann” refers to the Company’s Low-Vol metallurgical mining complex located in Wyoming County, West Virginia;

•“Leer” refers to the Company’s High-Vol metallurgical mining complex located in Taylor County, West Virginia;

•“Leer South” refers to the Company’s High-Vol metallurgical mining complex located in Barbour County, West Virginia;

•“Leer West” refers to the Company’s High-Vol metallurgical mining project located in Barbour County, West Virginia (collectively with Leer and Leer South, the “Leer Complex”);

•“Merger” refers to the Company’s all-stock merger of equals transaction with Arch that closed on January 14, 2025;

•“Merger Agreement” refers to the Agreement and Plan of Merger, dated as of August 20, 2024, by and among the Company, Merger Sub and Arch;

•“mmBtu” refers to one million British thermal units;

•“Mountain Laurel” refers to the Company’s High-Vol metallurgical mining complex located in Logan County and Boone County, West Virginia;

•“Pennsylvania Mining Complex” or “PAMC” refers to the Company’s Bailey, Enlow Fork and Harvey high calorific value thermal coal mines, and the Central Preparation Plant serving those mines, located in southwestern Pennsylvania and northern West Virginia; and

•“West Elk” refers to the Company’s high calorific value thermal mining complex located in Gunnison County, Colorado.

Certain statements in this Annual Report on Form 10-K (“Report”) are “forward-looking statements” within the meaning of the federal securities laws. With the exception of historical matters, the matters discussed in this Report are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that involve risks and uncertainties that could cause actual results and outcomes to differ materially from results expressed in or implied by our forward-looking statements. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “should,” “will,” “would,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Report speak only as of the date of this Report. We disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•deterioration in economic conditions or changes in consumption patterns of our customers may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•volatility and wide fluctuation in coal prices based upon a number of factors beyond our control;

•an extended decline in the prices we receive for our coal;

•significant downtime of our equipment or inability to obtain equipment, parts or raw materials;

•decreases in the availability of, or increases in the price of, commodities or capital equipment used in our coal mining operations;

•our reliance on major customers, our ability to collect payment from our customers and uncertainty in connection with our customer contracts;

•our inability to acquire additional coal reserves or resources that are economically recoverable;

•decreases in coal consumption patterns for steel production, electric power generation and industrial applications;

•the availability and reliability of transportation facilities and other systems that deliver our coal to market and fluctuations in transportation costs;

•a loss of our competitive position;

•inflation that could result in higher costs and decreased profitability;

•foreign currency fluctuations that could adversely affect the competitiveness of our coal abroad;

•risks related to the fact that a significant portion of our production is sold in international markets (and may grow) and our compliance with export control and anti-corruption laws;

•coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;

•the impact of current and future regulations to address climate change, the discharge, disposal and clean-up of hazardous substances and wastes and employee health and safety on our operating costs as well as on the market for coal;

•the risks inherent in coal operations, including being subject to unexpected disruptions caused by adverse geological conditions, equipment failure, delays in moving longwall equipment, railroad derailments or strikes, security breaches or terroristic acts and other hazards, delays in the completion of significant construction or repair of equipment, fires, explosions, seismic activities, accidents and weather conditions;

•failure to obtain or renew surety bonds, letters of credit or insurance coverages on acceptable terms;

•the effects of coordinating our operations with oil and natural gas drillers and distributors operating on our land;

•our inability to obtain financing for capital expenditures on satisfactory terms;

•the effects of our securities being excluded from certain investment funds as a result of environmental, social and corporate governance (“ESG”) practices;

•the effects of global conflicts on commodity prices and supply chains;

•the effect of new or existing laws or regulations or tariffs and other trade measures;

•our inability to find suitable joint venture partners, acquisition targets or similar investments or integrating the operations of future acquisitions or investments into our operations;

•obtaining, maintaining and renewing government permits and approvals for our coal operations;

•the effects of asset retirement obligations, employee-related long-term liabilities and certain other liabilities;

•uncertainties in estimating our economically recoverable coal reserves;

•defects in our chain of title for our undeveloped reserves or failure to acquire additional property to perfect our title to coal rights;

•the outcomes of various legal proceedings, including those which are more fully described herein;

•the risk of our debt agreements, our debt and changes in interest rates affecting our operating results and cash flows;

•information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;

•the potential failure to retain and attract qualified personnel of the Company;

•failure to maintain effective internal control over financial reporting;

•uncertainty with respect to the Company’s common stock, potential stock price volatility and future dilution;

•uncertainty regarding the timing and value of any dividends we may declare;

•uncertainty as to whether we will repurchase shares of our common stock;

•inability of stockholders to bring legal action against us in any forum other than the state courts of Delaware;

•the risk that the businesses of the Company and Arch will not be integrated successfully after the closing of the Merger;

•the risk that the anticipated benefits of the Merger may not be realized or may take longer to realize than expected; and

•other unforeseen factors.

The above list of factors is not exhaustive or necessarily in order of importance. Additional information concerning factors that could cause actual results to differ materially from those in forward-looking statements include those discussed under “Risk Factors” elsewhere in this report. The Company disclaims any intention or obligation to update publicly any forward-looking statements, whether in response to new information, future events, or otherwise, except as required by applicable law.

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.

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.

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.

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 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.

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.

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.

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 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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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:

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.

•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.

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.

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

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.

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.

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.

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):

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

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

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. 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, 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.

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

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.

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

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 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 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. 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. 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. 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. 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.

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):

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.

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.

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

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.

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 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.

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.

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.

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

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.

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 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.

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.

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.

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.

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.

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 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.

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 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.

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.

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

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.

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.

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.

Any of the following risks could materially and adversely affect our financial condition, results of operations or cash flows. Our operations could be affected by various risks, many of which are beyond our control. Based on current information, we believe that the following list identifies the most significant risk factors (not necessarily in order of importance or probability of occurrence) that could affect our financial condition, results of operations or cash flows. There may be additional risks and uncertainties that adversely affect our financial condition, results of operations or cash flows in the future that are not presently known, are not currently believed to be material, or are not identified below because they are common to all businesses. Past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods. For more information, see “Forward-Looking Statements.”

The following is a summary of the principal risks that could adversely affect our business, operations and financial results:

•deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•volatility and wide fluctuation in coal prices based upon a number of factors beyond our control including future plans to eliminate coal-fired electric power generation facilities, oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels and technologies;

•an extended decline in the prices we receive for our coal affecting our operating results and cash flows;

•our customers extending existing contracts or not entering into new long-term contracts for coal on favorable terms;

•our reliance on major customers;

•decreases in demand and changes in coal consumption patterns of industrial end users, metallurgical coal users and electric power generators;

•decreases in steel production from blast furnaces or advancement of alternative steel production technologies;

•the availability and reliability of transportation facilities and other systems, disruption of rail, barge, processing and transportation facilities and other systems that deliver our coal to market and fluctuations in transportation costs;

•the risks and uncertainties arising from a significant portion of our production being sold in international markets and complying with foreign laws and regulations, including anti-corruption laws;

•the impact of potential, as well as any adopted, regulations to address pollution and climate change, including any requirements relating to greenhouse gas emissions, on our operating costs as well as on the market for coal;

•the risks inherent in coal operations, including being subject to unexpected disruptions caused by adverse geological conditions, equipment failure, delays in moving out longwall equipment, railroad derailments, security breaches or terroristic acts and other hazards, delays in the completion of significant construction or repair of equipment, fires, explosions, seismic activities, accidents and weather conditions;

•the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal operations;

•uncertainties in estimating our economically recoverable coal reserves;

•failure to obtain or renew surety bonds or insurance coverage on acceptable terms;

•exposure to employee-related long-term liabilities;

•the risk of our debt agreements, our debt, access to capital markets and changes in interest rates affecting our operating results and cash flows;

•retaliatory tariffs by our trading partners on the price of coal we receive; and

•tariffs on the cost of supplies we procure from overseas vendors or that include foreign components.

•uncertainty with respect to the Company’s common stock, potential stock price volatility and future dilution;

•the consequences of a lack of, or negative, commentary about us published by securities analysts and media;

•uncertainty regarding the timing of any dividends we may declare;

•uncertainty as to whether we will repurchase shares of our common stock;

•restrictions on the ability to acquire us in our certificate of incorporation, bylaws and Delaware law and the resulting effects on the trading price of our common stock; and

•inability of stockholders to bring legal action against us in any forum other than the state courts of Delaware.

•uncertainties associated with the Merger may cause a loss of management personnel and other key employees;

•disruption of the Company’s business relationships due to uncertainty associated with the Merger;

•incurrence of significant costs in connection with the Merger and integration of Arch with the Company;

•failure to integrate the businesses and operations of the Company and Arch successfully in the expected time frame; and

•failure to realize all of the anticipated benefits of the Merger.

Weakness in the economic conditions of any of the industries we serve or that are served by our customers could adversely affect our business, financial condition, results of operations, cash flows and liquidity in a number of ways. For example:

•demand for electricity in the U.S. is impacted by industrial production, which, if weakened, would negatively impact the revenues, margins and profitability of our coal business;

•demand for metallurgical coal depends on coke and steel demand in the U.S. and globally, which, if weakened, would negatively impact the revenues, margins and profitability of our metallurgical coal business or our thermal coal as higher priced high-volatile metallurgical coal;

•demand for coal used in industrial applications depends on demand for products such as cement and brick used in construction and infrastructure projects, which, if weakened, would negatively impact the revenues, margins and profitability of our coal business;

•the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal reserves, or for strategic acquisitions of assets; and

•a decline in our creditworthiness, which may require us to post letters of credit, cash collateral or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

Our financial results are significantly affected by the prices we receive for our coal and depend, in part, on the margins that we receive on sales of our coal. Our margins reflect the price we receive for our coal over our cost of producing and transporting our coal. Prices and quantities under our multi-year sales contracts are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or re-opened. The expectation of future prices for coal depends upon many factors. In addition, demand can fluctuate widely due to a number of matters beyond our control, including:

•the market price for coal;

•changes in the consumption pattern of industrial consumers, electric power generators and residential end-users of electricity;

•weather conditions in our markets which affect the demand for thermal coal;

•competition from other coal suppliers;

•the price and availability of alternative fuels and sources for electric power generation, especially natural gas and renewable energy sources;

•with respect to thermal coal, the price and availability of natural gas and the price and supply of imported liquefied natural gas and competing sources of energy used in certain industrial applications, such as petroleum coke and metallurgical coal;

•technological advances affecting energy consumption and those related to hydrogen-based steel production;

•with respect to metallurgical coal, the overall demand for steel, which may be affected by competition for production of steel from non-coal sources, including electric arc furnaces or other processes that may use alternatives to coking as a reduction agent, which may limit demand for coking coal;

•the costs, availability and capacity of transportation infrastructure;

•overall domestic and global economic conditions, including the supply of and demand for domestic and foreign coal;

•international developments impacting supply of thermal and metallurgical coal, including supply side reforms promulgated in China, and continued expected growth in demand for seaborne metallurgical coal in India;

•the imposition of tariffs, quotas, trade barriers and other trade protection measures; and

•the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry, blast furnaces, and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.

We depend on several major pieces of mining equipment to produce, transport and prepare our coal for our customers, including, but not limited to, longwall mining systems, continuous mining units, our preparation plants and related facilities, conveyors and transloading facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost, which would impact our ability to produce and transport coal and materially and adversely affect our business, results of operations, financial condition and cash flows. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies can be high, and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment or the cancellation of our supply contracts under which we obtain equipment could limit our ability to obtain these supplies or equipment. Disruptions in supply chains, increased demand and other factors have recently led to increases in these lead times and delays, which could reduce our production and therefore adversely affect our results of operations, financial condition and cash flows.

Additionally, coal production, transportation and preparation consumes large quantities of commodities including steel, copper, explosives, rubber products and liquid fuels and requires the use of capital equipment. We also use significant amounts of diesel fuel, explosives and tires for trucks and other heavy machinery, particularly at our Black Thunder mining complex. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations, whether as a result of increased demand, shortages caused by supply chain disruptions or general inflationary pressures, could impact our mining operating costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel in the mining process. If the price of steel or other materials increases substantially, the risk of which is currently elevated due to economy-wide high inflation, or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially and adversely impact our business, financial condition, results of operations and cash flows.

During the year ended December 31, 2025, approximately 69% of the coal the Company produced was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or terminated, if force majeure clauses are exercised, or if we are unable to replace or extend the contracts or new contracts are priced at lower levels, our profitability would be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have existing contractual obligations, our revenues will decrease and we may have to reduce production at our mines until such customers honor their contractual obligations and begin accepting shipments of our coal again.

The profitability of our multi-year sales contracts to supply coal depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, during periods of declining market prices, provisions in our long-term coal contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price and electric power price volatility.

As a result, we may not be able to obtain long-term agreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, which may reduce our profitability.

A significant portion of our coal is sold in the export market, and we remain somewhat exposed to risks associated with a concentrated customer base both domestically and globally. There are inherent risks whenever a significant percentage of total revenues is concentrated with a limited number of customers. Revenues from our largest customers may fluctuate from time to time based on numerous factors, including market conditions, which may be outside of our control. If any of our largest customers experience declining revenues due to market, economic or competitive conditions, we could be pressured to reduce the prices that we charge for our coal, which could have an adverse effect on our margins, profitability, cash flows and financial position. If any customers were to significantly reduce their purchases of coal from us, including by failing to buy and pay for coal they committed to purchase in sales contracts, our business, financial condition, results of operations and cash flows could be adversely affected.

Our ability to collect payments from our customers for coal sold and delivered could be impaired if their creditworthiness declines or if they fail to honor their contracts. If the creditworthiness of a significant customer declines or the customer significantly delays payments to us, our business, cash flows and financial condition could be materially and adversely affected. If we determine that a customer is not creditworthy, we may be able to withhold delivery under the customer’s coal sales contract. However, if this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation or if we terminate a relationship with a significant customer due to credit risks, our revenue could decrease materially and we may have to reduce production at our mines until our customers’ contractual obligations are honored or we are able to replace a significant customer. In addition, our borrowing capacity under our receivables financing arrangement could be reduced if we experience prolonged and significant delays in payments by one or more material customers.

Also, our customer base may change if domestic utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. Some power plant owners may have credit ratings that are below investment grade or may become below investment grade after we enter into contracts with them. Furthermore, our metallurgical customers operate in a highly competitive and cyclical industry where their creditworthiness could deteriorate rapidly.

Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics that our customers desire. Because our reserves decline as we mine our coal, our future profitability depends upon our ability to acquire additional coal reserves and surface land needed to ensure the reserves are economically recoverable to replace the reserves we produce. If we fail to acquire, gain access to or develop sufficient additional reserves over the long term to replace the reserves depleted by our production, our existing reserves will eventually be depleted, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have pursued, and will continue to pursue, a variety of new lines of business, including alternative and innovative uses of coal led by our subsidiary, CONSOL Innovations LLC, including, but not limited to, products with aerospace, defense, battery and building product applications, and potential new lines of business involving rare earth elements (“REEs”). Additional information regarding these new lines of business can be found in “Our Strategy” in Item 1 of this Report. Pursuing new lines of business subjects us to a number of material risks, including, but not limited to:

•the possibility that we may invest significant time and resources in our attempts to pursue new lines of business that may never be profitable;

•exposure to new laws and regulations with which we are not familiar and which may lead to increased litigation and regulatory risk;

•unanticipated liabilities or contingencies;

•difficulty in hiring personnel or acquiring the know-how needed to operate any new line of business; and

•failure of our management team to successfully manage new and shifting risk considerations, compliance obligations, competitors or market preferences.

In particular, as we continue to evaluate a potential new line of business involving REEs, our strategy may include expanding into the exploration, development, extraction, processing, separation, or commercialization of REEs and related downstream activities. These initiatives are subject to significant uncertainty and may require substantial capital investment, specialized technical expertise, proprietary or emerging processing technologies and extensive regulatory approvals. Volatility in commodity pricing and other market dynamics, competition from established participants and fluctuations in demand for REEs may adversely affect the economic viability of such new lines of business.

In addition, REE deposits often present complex mineralogy, low concentrations and challenging metallurgy, requiring specialized beneficiation, separation and refining processes. Even where REEs are identified, the economic feasibility of extraction and processing may be constrained by high operating and capital costs. Furthermore, recoveries of individual REEs may vary significantly, and unfavorable element mixes may reduce the overall economic value of a deposit. If the extraction, processing or sale of REEs proves to be economically unviable, we may be unable to recover any investments in REE-related initiatives, which may impact future profitability.

Our business is closely linked to demand for electricity, and any changes in coal consumption by U.S. or international electric power generators would likely impact our business over the long term. According to the EIA, in 2025, the domestic electric power sector accounted for approximately 92% of total U.S. coal consumption. During the year ended December 31, 2025, the Company sold approximately 68% of its sales tons to U.S. electric power generators, and we have annual or multi-year contracts in place with many of these electric power generators for a significant portion of our future production. The amount of coal consumed by the electric power generation industry is affected by, among other things:

•general economic conditions, particularly those affecting industrial electric power demand, such as a downturn in the U.S. or international economy and financial markets;

•overall demand for electricity;

•indirect competition from alternative fuel sources for electric power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;

•environmental and other governmental regulations, including those impacting coal-fired power plants;

•energy conservation efforts and related governmental policies; and

•other corporate environmental, social or governance initiatives to reduce dependency on and/or consumption of fossil fuels.

Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired power plants has displaced a significant amount of coal-fired electric power generation and may continue to do so 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 could also affect demand for our coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the electric power generation industry could adversely affect the price of coal, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Other factors, such as efficiency improvements associated with new appliance standards in the buildings sectors and overall improvement in the efficiency of technologies powered by electricity, have slowed electricity demand growth and may contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession, government-imposed lockdowns designed to slow or contain the spread of contagious diseases or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.

Coal sold into the industrial markets is used in the cement and brick manufacturing process. Any deterioration in the U.S. or foreign cement and brick industries, including a decrease in demand for such products or concerns regarding the continued financial viability of these industries, could reduce the demand for our coal sold into those markets and could adversely impact the creditworthiness of our U.S. or foreign industrial customers and our ability to receive timely payments from these customers. In addition, we compete heavily against the price of petroleum coke into these industries and as the price of petroleum coke changes, that could positively or negatively affect our financial condition, results of operations and cash flows.

The metallurgical coal that we produce is sold to domestic and export customers involved in the production of steel. Any deterioration in conditions in the U.S. or foreign steel industries, including a decrease in demand for steel or concerns regarding the continued financial viability of the industry, could reduce the demand for our metallurgical coal and could adversely impact the creditworthiness of our U.S. or foreign metallurgical coal customers and our ability to receive timely payments from these customers. In addition, the steel industry’s demand for coal is affected by a number of factors, including the variable nature of that industry’s business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites or plastics. When steel prices are lower, the prices that we charge steel industry customers for our metallurgical coal may decline, which could adversely affect our financial condition, results of operations and cash flows.

Also, premium High-Vol metallurgical coal generally commands a price premium over other forms of coal because of its value in use in blast furnaces for steel production. Premium High-Vol metallurgical coal has specific physical and chemical properties that can impact the efficiency of blast furnace operation. Alternative technologies are continually being investigated and developed with a view to reducing production costs or for other reasons, such as minimizing environmental or social impact. If competitive technologies emerge or are increasingly utilized that use other materials in place of our product or that diminish the required amount of our product, such as electric arc furnaces or pulverized coal injection processes, demand and price for our metallurgical coal might fall. Many of these alternative technologies are designed to use lower quality coals or other sources of carbon instead of higher cost High-Vol metallurgical coal. Over the longer term, the emergence of competitive technologies not reliant on High-Vol metallurgical coal could reduce demand and price premiums for High-Vol metallurgical coal.

Transportation logistics play a critical role in allowing us to supply coal to our customers. Any significant delays, interruptions or other limitations on the ability to transport our coal could negatively affect our operations. Our coal is transported from our mines primarily by rail. To reach markets and end customers, our coal may also be transported by barges or by ocean vessels loaded at terminals, including our wholly-owned Core Marine Terminal as well as the Dominion Terminal, operated by DTA, in which we own a 35% interest following the Merger. Disruption of transportation services because of weather-related problems, strikes, lock-outs, terrorism, governmental regulation, third-party action or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. For example, after a container ship struck a support column of the Francis Scott Key Bridge in Baltimore, Maryland causing it to collapse on March 26, 2024, vessel access in and out of the Core Marine Terminal, which is located in the Port of Baltimore, was suspended. Until a channel was opened to normal operations on June 10, 2024, our inability to ship coal to our customers from the Core Marine Terminal temporarily negatively impacted our business, financial condition and results of operations. In addition, transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuation in the price of diesel fuel and demurrage, could make our coal less competitive. Any disruption of the transportation services we use or increase in transportation costs could have a materially adverse effect on our business, financial condition, results of operations and cash flows. Disruption in shipment levels over longer periods of time at our East Coast terminals could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and results of operations.

We compete with other producers primarily on the basis of price, coal quality, transportation costs and reliability of delivery. We compete with coal producers in various regions of the U.S. and with some foreign coal producers for domestic sales primarily to electric power generators. We also compete with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies such as natural gas and petcoke, and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric, wind and solar power.

We sell coal to foreign industrial end-users, electric power generators and to the more specialized metallurgical coal market, which are significantly affected by international demand and competition. The coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. Current or further consolidation in the coal industry or current or future bankruptcy proceedings of coal competitors may adversely affect us.

In addition, increases in coal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. If overcapacity results, the prices of and demand for our coal could significantly decline, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, we face competition from foreign producers that sell their coal in the export market. Potential changes to international trade agreements, trade concessions 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 with 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 foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign 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 U.S., European Union and other large economies have recently experienced inflation at a rate significantly higher than recent years. While inflation has been easing, there can be no guarantee that this trend will continue. Current and future inflationary effects may be driven by, among other things, governmental stimulus and monetary policies, supply chain disruptions and geopolitical instability. This recent inflation has resulted in rising prices, including increases in freight rates, prices for energy and other costs, and has adversely impacted us and may further impact us negatively in the future. Sustained inflation could result in higher costs for transportation, energy, materials, supplies and labor. Our ability to recover inflation-driven cost increases may be constrained by the terms of our contracts, the competitive nature of the contract bidding process and the economic and industry conditions prevailing in the countries to which we sell our export coal. Significant inflation may have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the U.S., which could increase our cost of debt borrowing in the future.

For the years ended December 31, 2025, 2024 and 2023, approximately 56%, 66% and 71%, respectively, of our annual coal revenue was derived from customers who exported our coal outside of the U.S., and we expect that international sales will continue to account for a large portion of our revenue as we seek international expansion opportunities. The international markets are subject to a number of material risks, including, but not limited to:

•changes in a specific country’s or region’s political, economic or other conditions;

•changes in U.S. government policy with respect to certain foreign countries may inhibit export of our products and limit potential customers’ access to U.S. dollars in a country or region in which those potential customers are located;

•we may experience difficulties in enforcing our legal contracts or the collecting of foreign accounts receivable in a timely manner, and we may be forced to write off these receivables;

•longer sales cycles and time to collection may produce large swings in working capital from period to period;

•tariffs and other international trade barriers may make our products less cost competitive;

•government currency controls;

•potentially adverse tax consequences to our customers may damage our cost competitiveness;

•customs, import/export and other regulations of the countries in which our international customers are located may adversely affect our business;

•currency fluctuations may make our coal less cost competitive, affecting overseas demand for our coal, or may indirectly expose us to currency fluctuation risk;

•geopolitical uncertainty or turmoil, including terrorism, war and natural disasters; and

•unexpected changes in diplomatic and trade relationships.

Our sales are also affected by general economic conditions in our international markets. A prolonged economic downturn in international markets could have a material adverse effect on our business. Negative developments in one or more countries or regions in which our coal is exported could result in a reduction in demand for our coal, the cancellation or delay of orders already placed, difficulties in delivering our products, difficulty in collecting receivables or a higher cost of doing business, any of which could negatively impact our business, financial condition, cash flows and results of operations. In addition, we may be exposed to legal risks under the laws of the countries outside the U.S. in which we do business, as well as the laws of the U.S. governing our business activities in those other countries, such as the U.S. Foreign Corrupt Practices Act.

Because we sell a significant portion of our production in international markets, our operations and activities inside and outside the U.S., as well as the shipment of our products across international borders, require us to comply with a number of federal, state, local and foreign laws and regulations, which are complex and increase our risks of doing business internationally. These laws and regulations include import and export requirements, tariffs and other international trade barriers, government currency controls, economic sanction laws, customs laws, tax laws and anti-corruption laws, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act. In addition, we have sales offices in Singapore and the United Kingdom which sell our coal to new international customers, which may present uncertainties and new risks, including potential liability under foreign anti-corruption and other laws. We cannot predict how these laws or their interpretation, administration and enforcement will change over time. There can be no assurance that our employees, contractors, agents, distributors, customers, payment parties or third parties working on our behalf will not take actions in violation of these laws. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions, and might adversely affect our business, financial condition, results of operations and cash flows. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter, nitrogen oxides and carbon dioxide when it is burned. Complying with regulations on these emissions can be costly for our customers, including those in the industrial, metallurgical and electric power generation markets. In order to comply with emissions standards promulgated under the federal Clean Air Act or similar state regulations seeking to limit the emissions that are generated as a result of coal combustion, coal users could be required to install costly emissions control devices, use or purchase emissions credits or allowances, curtail operations or switch to other fuels, each of which has limitations. Because thermal coal currently accounts for a significant portion of our sales, our results could be materially affected by the extent to which our customers incur costs associated with controlling or limiting emissions from the use of coal or switch to alternative fuels. Rulemakings such as the Cross State Air Pollution Rule (“CSAPR”), the National Ambient Air Quality Standards (“NAAQS”), or the New Source Performance Standards (“NSPS”) and other Clean Air Act regulations may decrease the demand for our coal in industrial, metallurgical or electric power generation markets in the future. For more information, please see “Laws and Regulations” under Item 1 above.

The issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity (especially the emissions of GHGs such as carbon dioxide and methane). Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere by coal end-users, such as coal-fired power plants. Additionally, methane released during our coal mining operations is ventilated to the atmosphere in order to promote a safe working environment for our miners underground.

Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Foreign governments, including the European Union and member countries, have adopted regulations governing GHG emissions. Independent of regulation, the UNFCCC seeks to establish GHG emissions 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. Nevertheless, the international community has been called upon to achieve a 43% reduction in GHG emissions by 2030 (compared to 2019 levels) through actions that drive the transition away from fossil fuels in energy systems. 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.

In addition, several individual U.S. states have already adopted measures requiring GHG emissions reductions or a shift to renewable energy sources within their boundaries. Other states have elected to participate in regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (“RGGI”) in the northeastern U.S. Any significant legislative changes at the international, national, state or local levels designed to reduce GHG emissions could significantly affect our ability to produce and sell our coal and develop our reserves, could increase the cost of the production and sale of coal and could materially reduce the value of our coal and coal reserves.

These potential legislative changes, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-coal fuel sources, including natural gas and/or alternative energy sources, could cause coal prices and sales of our coal to materially decline and could cause our costs to increase. Further, climate change itself may cause more extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our services and increase our costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Furthermore, adoption of comprehensive legislation or regulation focusing on climate change or GHG emissions reductions for the U.S. or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired power plants, may make it more costly to operate coal-fired power plants and make coal less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas and/or alternative energy sources could gain added economic benefits versus coal-fired power generation, especially if such regulation or legislation makes our coal more expensive as a result of increased compliance, operating and maintenance costs. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired power plants to replace older plants or investing in the upgrading of existing coal-fired power plants. Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of GHG emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. Our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal and comply with future GHG emissions standards. Although we cannot predict the ultimate impact of any legislation or regulation, it is likely that any future laws, regulations or other policies aimed at reducing GHG emissions will negatively impact demand for our coal and could also negatively affect the value of our reserves and other assets.

Additionally, if emissions of methane from coal mines are regulated in the future, we would likely be required to install additional pollution control devices, pay fees or taxes for our emissions or incur expenses associated with the purchase of emissions credits in order to continue operation. Alternatively, we may need to curtail coal production. The magnitude of impact on our operations, capital expenditures, financial condition or cash flows would be dependent on the structure of any proposed regulation and the degree of emissions reduction prescribed.

Increasing attention to climate change risk has also resulted in governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. For instance, we have been named as a defendant in multiple lawsuits brought by the City of Baltimore, the State of Delaware, the City of Annapolis, and Anne Arundel County, Maryland seeking to hold us and other energy companies liable for the effects of climate change caused by the release of GHGs. The outcome of this litigation is uncertain, due to the range of legal theories and the various court systems in which they are taking place, including for appeals. Even if we are ultimately successful, we could incur substantial legal costs associated with defending these and similar lawsuits in the future. Government entities in other states, as well as private plaintiffs, have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for climate-related impacts or for insufficient disclosure of associated risks, often seeking unspecified damages and abatement under various tort theories. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities, relating to the protection of the environment. These include legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the installation of various safety equipment in our mines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position.

In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities, or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations and competitive position.

Certain of our coal mining operations are underground mines. Underground mining and related processing activities present inherent risks of injury or death to persons, damage to property and equipment and other potential legal or other liabilities. We also have surface mining operations that utilize explosives to remove the earth and rock covering the coal, which creates additional hazards. Our mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time, thereby adversely affecting our operating results. In addition, if an operating risk occurs in our mining operations, we may not be able to produce sufficient amounts of coal to deliver under our multi-year coal contracts. Our inability to satisfy contractual obligations could result in our customers initiating claims against us or canceling their contracts. The operating risks that may have a significant impact on our coal operations include:

•variations in thickness of the layer, or seam, of coal;

•adverse geological conditions, including amounts of rock and other natural materials intruding into the coal seam that could affect the stability of the roof and the side walls of the mine;

•environmental hazards;

•equipment failures or unexpected maintenance problems;

•fires or explosions, including as a result of methane, coal, coal dust or other explosive materials and/or other accidents;

•inclement or hazardous weather conditions and natural disasters or other force majeure events;

•seismic activities, ground failures, rock bursts or structural cave-ins or slides;

•delays in moving our longwall equipment;

•railroad derailments and mandated delays;

•security breaches or terroristic acts; and

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

The occurrence of any of these risks at our coal mining operations could adversely affect our ability to conduct our operations or result in substantial loss to us, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows. For example, in January 2025, the Company sealed the Leer South mine’s active longwall panel in order to extinguish isolated combustion-related activity at the mine and did not resume longwall operations until December 2025. In addition, the occurrence of any of these events in our coal mining operations which prevents our delivery of coal to a customer and which is not excusable as a force majeure event under our coal sales agreement could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the coal sales agreement, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our coal operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Moreover, a significant mine accident could potentially cause a mine shutdown. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. Over the past few years, the insurance and surety markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and/or fewer providers willing to underwrite policies and surety bonds. Terms have generally become more 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 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. In addition, federal and state regulators are considering making financial assurance requirements more stringent and costly with respect to self-insured coal workers’ pneumoconiosis, mine closure and reclamation security amounts. Because we are required by federal and state law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal, and incurring additional rising costs to obtain and maintain such arrangements could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, coal and other mining companies are increasingly struggling to obtain adequate insurance coverage for their business and operations. Our failure to obtain adequate insurance coverages could have a material adverse effect on our business and results of operations. Further cost burdens on our ability to maintain adequate insurance and bond coverage may adversely impact our operations, financial position and liquidity.

Substantially all of our coal reserves are in areas containing shale oil and natural gas plays, including the Marcellus Shale, which are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If we have received a permit for our mining activities, then while we may have to coordinate our mining with such oil and natural gas drillers and transporters, our mining activities will have priority over any oil and natural gas drillers and transporters with respect to the land covered by our permit. Oil and natural gas drillers and transporters may be subject to laws and regulations that are enforced by regulators that do not have jurisdiction over our activities. Any conflict between our rights and the enforcement actions by any regulator of oil or natural gas-specific rights that conflict with our rights to mine could result in additional costs and possible delays to mining.

For reserves outside of our permits, we engage in discussions with drilling and transport companies on potential areas on which they can drill that may have a minimal effect on our mine plan. If a well is in the path of our mining for coal on land that has not yet been permitted for our mining activities, we may not be able to mine through the well unless we purchase it. The cost of purchasing a producing horizontal well could be substantially greater than that of a vertical well. Horizontal wells with multiple laterals extending from the well pad may access larger oil and natural gas reserves than a vertical well, which would typically result in a higher cost to acquire. The cost associated with purchasing oil and natural gas wells that are in the path of our coal mining activities could likewise make mining through those wells uneconomical, thereby effectively causing a loss of significant portions of our coal reserves, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

Our operations may also face potential conflicts with holders of other mineral interests such as coalbed methane, natural gas and oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal reserves and active operations, potentially creating conflicting interests between us and the holders of those interests. From time to time, we acquire these minerals ourselves to prevent conflicting interests from arising. If, however, conflicting interests arise and we do not acquire the competing mineral rights, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. If we are unable to reach an agreement with the holders of such rights, or to do so on a cost-effective basis, we may incur increased costs, and our ability to mine could be impaired, which could materially and adversely affect our business, results of operations, financial condition and cash flows.

In order to maintain, grow and diversify our business, we will need to make substantial capital expenditures to fund our share of capital expenditures associated with our mines, acquisitions or other business development initiatives. Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations requires substantial capital expenditures. While a significant amount of the capital expenditures required to build out our mining infrastructure has been spent, we must continue to invest capital to maintain or to increase our production.

Decisions to increase our production levels could also affect our capital needs. Our production levels may decrease or may not be able to generate sufficient cash flow, or we may not have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional equity securities. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control, such as financial institutions and investors abandoning the thermal coal sector. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant stockholder dilution.

Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based upon ESG or “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but companies in the energy industry, and in particular those focused on coal, natural gas or petroleum extraction and refining, often perform less well under ESG assessments compared to companies in other industries. The importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders, and poor performance or perceived performance on various ESG matters could result in our securities, both debt and equity, being excluded from the portfolios of certain investment funds and investors. Additionally, many investment funds and investors are beginning to avoid securities issued by any company in the coal, natural gas or petroleum extraction or refining business, regardless of their particular ESG or sustainability score. Relatedly, banks and investment banks based both domestically and internationally have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power plants which may make it more difficult for utilities to obtain financing for coal-fired power plants. The impact of such efforts may adversely affect the demand for and price of securities issued by us and impact our access to the capital and financial markets. As such, our access to capital to fund our continuing operations and growth and diversification opportunities could become more restricted. Additionally, various policymakers have adopted or are considering adopting requirements for certain disclosures or other actions regarding climate or other ESG-related matters. These regulations are not uniform, and other policymakers have advocated for positions to restrict companies’ consideration of ESG factors. Such regulations increase the cost and complexity of compliance and associated risks.

While we may publish voluntary disclosures regarding ESG matters or take other actions from time to time in an effort to improve the ESG profile of our operations or products, we cannot guarantee that these efforts will have the desired effect. For example, our voluntary disclosures may include statements based on assumptions, estimates or third-party information we believe to be reasonable, but which may be uncertain, variable or erroneous. In addition, we may commit to certain ESG initiatives over time, such as investing capital in projects and technologies to reduce our greenhouse gas emissions profile; however, we may not ultimately be able to achieve our goals or reach our commitments, either on the timeframes or costs initially anticipated or at all, due to factors within or outside of our control. Various business units or components of the Company have previously established climate change-related goals and targets. As a result of the Merger and continued efforts to harmonize policies across the new, combined company, the Company has suspended its previous goals and targets and is in the process of reevaluating those policies for the Company as a whole. However, stakeholder expectations vary and, at times, can conflict. Any failure to successfully address such expectations, including regulatory developments, may result in reputational damage, loss of customers or other adverse stakeholder engagement and an increased risk of litigation or activism, which could materially and adversely affect our business, financial condition and results of operations.

Finally, various of our customers and other stakeholders are subject to similar risks and expectations, which may augment or result in additional risks to us. For example, a part of our business plan is to regularly and rigorously evaluate opportunities for acquisitions, joint ventures and other business arrangements in the coal industry and related industries that complement our core operations. We may face greater difficulties in finding partners for such acquisitions, joint ventures or other business arrangements if these potential partners are less willing or unwilling to enter into transactions with companies that have a low ESG or sustainability score or companies that engage in fossil fuel activities, which could have a material adverse effect on our ability to expand our business, and therefore, our financial condition, results of operations and cash flows could be negatively impacted.

The extent and duration of the military conflict involving Russia and Ukraine, resulting sanctions and future market or supply disruptions in the region are impossible to predict, but could be significant and may have a severe adverse effect on the region. Globally, various governments have banned imports from Russia including commodities such as oil, natural gas and coal. In addition, there have been a series of recent armed conflicts in the Middle East involving Israel, Iran, Lebanon, Iraq, Syria and Yemen, alongside armed non-state actors including Hezbollah, Hamas and the Houthis. There is also political instability in Venezuela after the U.S. captured and extradited Venezuela’s President Nicolas Maduro. These events have caused volatility in the aforementioned commodity markets. Although the Company has not experienced any material adverse effect on its results of operations, financial condition or cash flows as a result of these events or the resulting volatility as of the date of this Report, such volatility, including market expectations of potential changes in coal prices and inflationary pressures on steel products, may significantly affect prices for our coal or the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers, like natural gas.

These conflicts, trade and monetary sanctions, as well as any escalation of these conflicts and future developments, could significantly affect worldwide market prices and demand for our coal and cause turmoil in the capital markets and generally in the global financial system. In addition, due to the increasing importance of exports to our business, a disruption in the supply chain or network we rely on to export our coal could adversely affect our business and result in lost sales and increased expenses. Our ability to export coal is dependent on third-party ocean-going container ships, rail, barge, air and trucking systems and, therefore, disruption in these logistics services because of global conflicts, including recent attacks in the Middle East on container ships, could adversely affect our financial performance and financial condition, negatively impacting sales, profitability and cash flows. Either of these risks could have a material adverse effect on our business, financial condition and results of operations, along with our operating costs, making it difficult to execute our planned capital expenditure program. Additionally, the geopolitical and macroeconomic consequences of these conflicts and associated sanctions cannot be predicted but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for coal-fired electricity, steel made through the use of metallurgical coal or our coal generally, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations, financial condition and cash flows.

New or existing tariffs and other trade measures could adversely affect our business, results of operations, financial condition and cash flows, either directly or indirectly through various adverse impacts on our significant customers. During the last several years, the U.S. Government imposed tariffs on steel and aluminum and a broad range of other products imported into the U.S. In response to the tariffs imposed by the U.S., the European Union, Canada, Mexico and China have announced tariffs on U.S. goods and services. These actions are unprecedented and have caused substantial uncertainty and volatility in financial markets. These tariffs, along with any additional tariffs or trade restrictions that may be implemented by the U.S. or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the U.S. or other potentially adverse economic outcomes. Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations. Additionally, we sell coal into the export thermal market and the export metallurgical market. Accordingly, our international sales may also be impacted by the tariffs and other restrictions on trade between the U.S. and other countries. Retaliatory tariffs by regions outside the U.S. may impact the prices of our exported products and the profit realized from these exports. In addition, on November 5, 2025, the U.S. Supreme Court heard oral arguments on tariffs imposed under the International Emergency Economic Powers Act (“IEEPA”). The court may provide tariff relief and the potential recovery of amounts previously paid. We are monitoring developments in this case and its impact on our future financial statements and business. We cannot predict further developments, and such existing or future tariffs could impact trade agreements entered into by the U.S. and the wider tariff environment in which we operate or have a material adverse effect on our business, results of operations, financial condition and cash flows.

From time to time, we may evaluate and acquire assets and businesses that we believe complement our existing assets and business. However, our ability to grow our business through acquisitions or the entry into joint ventures may be limited by both our ability to identify appropriate acquisition or partner candidates and our financial resources, including our available cash and borrowing capacity.

Additionally, the assets and businesses we acquire or in which we take an ownership stake through a joint venture may be dissimilar from our existing lines of business. Acquisitions and joint venture operations may require substantial capital or the incurrence of substantial indebtedness and potentially may not be on favorable terms. Our capitalization and results of operations may change significantly as a result of future acquisitions and joint ventures. Acquisitions, joint ventures and business expansions involve numerous risks, including the following:

•difficulties in the integration of the assets and operations of the acquired businesses;

•inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas;

•the possibility that we have insufficient expertise to engage in such activities profitably or without incurring inappropriate amounts of risk;

•potential lack of control over a joint venture’s business decisions and operations; and

•the diversion of management’s attention from other operating issues.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Entry into certain lines of business may subject us to new laws and regulations with which we are not familiar and may lead to increased litigation and regulatory risk. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions. If a new business generates insufficient revenue or if we are unable to efficiently manage our expanded operations, our results of operations may be adversely affected.

Additionally, our participation in joint venture arrangements necessarily involves risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact our results of operations, financial condition, cash flows or impair our ability to recover our investment in the joint venture. Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational and other standards. Failure by non-controlled joint venture partners to adhere to operational standards that are equivalent to ours could unfavorably affect safety results, operating costs and productivity and accordingly, adversely impact our results of operations, financial condition and cash flows.

Our coal production is dependent on our ability to obtain various federal and state permits and approvals to mine our coal reserves. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators. For example, under Section 404 of the Clean Water Act, the Army Corps of Engineers (“Corps”) issues permits for the discharge of dredged or fill material into regulated waters and wetlands, and under Section 401 of the Clean Water Act, affected states must certify that proposed activity under Section 404 will comply with water quality standards or other applicable requirements. Corps permits and state certifications are required for construction of slurry ponds, refuse areas, impoundments, and for various other mining activities. The Section 404/401 permitting process has become subject to increasingly stringent regulatory requirements and challenges by environmental organizations. Where authorization by a federal agency is required, the federal agency may be required to complete reviews under the National Environmental Policy Act, which can require consideration of multiple facets of environmental impact including GHG emissions associated with the proposed project, and may incorporate such considerations in its approval or denial. In addition, the public, including non-governmental organizations and individuals, has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. It is possible that all permits required to commence new operations, or to expand or continue operations at existing facilities, may not be issued or renewed in a timely manner, or may not be approved at all. Furthermore, permits could be issued with operating requirements or special conditions that increase the cost of operations. Any of these circumstances could have significant negative effects and could materially and adversely affect our results of operations and cash flows.

The Federal Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose stringent health and safety standards on mining operations. Regulations that have been adopted are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures and other matters.

States in which we operate have programs for mine safety and health regulation and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations and potentially lead to penalties for the violation of such requirements, creating a significant effect on operating costs and productivity. In addition, government inspectors, under certain circumstances, have the ability to order our operations to be shut down based on safety considerations. If an incident were to occur at one of our coal mines, it could be shut down for an extended period of time and our reputation with our customers could be materially damaged.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages, as well as for the investigation and clean-up of soil, surface water, groundwater and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share. In addition, government inspectors, under certain circumstances, may have the ability to order our operations to be shut down based on a perceived or actual violation of regulations concerning hazardous substances and other matters related to environmental protection. These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.

We maintain coal refuse disposal areas (“CRDAs”), slurry impoundments and other water retaining or dam structures that are active or in various stages of reclamation at our active mines and at certain legacy properties. Such areas and impoundments are subject to extensive regulation and are designed, constructed, operated and maintained according to stringent environmental, structural and safety standards. In addition to routine inspections conducted by multiple regulatory authorities, these facilities are also inspected by qualified third-party inspectors and are separately certified by an independent professional engineer where required by law or regulation. Structural failure of a CRDA, slurry impoundment or other dam structure classified as a high or significant hazard could result in extensive damage to the environment and natural resources, such as bodies of water, as well as liability for related personal injuries, property damages, injuries to wildlife or loss of life. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of these structures were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, claims for personal injury or loss of life, and claims for physical property damage, as well as fines and penalties. These events could materially and adversely impact our business, financial condition, results of operations and cash flows.

Our future success depends upon the continued services of our executive officers, including our Chair and Chief Executive Officer as well as our President and Chief Financial Officer, who have critical experience and relationships in the coal industry that we rely on to implement our business plan and growth strategy. Our ability to retain senior management has in the past been, and may in the future be, impacted by volatility in commodity prices and uneven business performance, which have negatively impacted our stock price, and therefore, our ability to use equity compensation as a retention tool. Additionally, the recent efforts of certain members of the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote divestment of fossil fuel equities, to encourage the consideration of ESG practices of companies in a manner that negatively affects coal companies and to pressure lenders to limit funding to companies engaged in the extraction of fossil fuel reserves may also negatively impact our ability to attract and retain key management personnel. Accordingly, we have entered into, and may need to enter into additional, retention or other arrangements that could be costly to maintain. While we have change-in-control agreements in place with our senior executives, there can be no assurance we will continue to retain their services, and we may become subject to significant severance payments if our relationship with these executives is terminated under certain circumstances. Further, turnover, planned or otherwise, in these or other key leadership positions may materially adversely affect our ability to manage our business efficiently and effectively, and such turnover can be disruptive and distracting to management, may lead to additional departures of existing personnel and could have a material adverse effect on our results of operations and future profitability.

Our ability to retain our key management personnel or to identify and attract additional management personnel or suitable replacements should any members of the management team leave or be terminated is dependent on a number of factors, including the competitive nature of the employment market and our industry. Any failure to retain key management personnel or to attract additional or suitable replacement personnel could cause uncertainty among investors, employees, customers and others concerning our future direction and performance and could have a material adverse effect on our business, financial condition and results of operations.

The SMCRA and various state laws establish operational, reclamation and closure standards for all our coal mining operations and require us, under certain circumstances, to plug natural gas wells. We accrue for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total asset retirement obligations, which are based upon permit requirements, engineering studies and our engineering expertise related to these requirements, were approximately $535 million at December 31, 2025. The amounts recorded are dependent upon a number of variables, including the estimated future expenditures, estimated mine lives, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient, our future operating results could be adversely affected.

We also provide various long-term employee benefits to inactive and retired employees, and we accrue amounts for these obligations. At December 31, 2025, the current and non-current portions of these obligations included:

•postretirement medical and life insurance ($206 million);

•coal workers’ pneumoconiosis benefits ($286 million);

•non-qualified pension plan benefits ($23 million);

•workers’ compensation ($88 million); and

•long-term disability ($5 million).

Our management and engineers periodically review these estimates. However, if our assumptions are inaccurate, major operational changes are implemented or if government regulations change significantly, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with Employer Retirement Income Security Act of 1974 (“ERISA”) regulations. The other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in workers’ compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense and our collateral requirements. Additionally, former miners and their family members asserting claims for pneumoconiosis benefits have generally been more successful asserting such claims in recent years as a result of the presumption within the PPACA of 2010 that a coal miner with 15 or more years of underground coal mining experience (or the equivalent) who develops a respiratory condition and meets the requirements for total disability under the Federal Act is presumed to be disabled due to coal dust exposure, thereby shifting the burden of proof from the employee to the employer/insurer to establish that this disability is not due to coal dust. The increasing success rate of such claims based upon the PPACA changed presumption and, as a result, the increasing expense incurred by us to insure against such claims could increase our expenses for long-term employee benefit obligations.

Coal reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of production and selling. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our coal reserve information on geological data, coal ownership information and current and proposed mine plans. These estimates are periodically updated to reflect past coal production, new drilling information and other geological or mining data. There are numerous uncertainties inherent in estimating quantities and qualities of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff and external consultants. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

•geological and mining conditions;

•historical production from the area compared with production from other producing areas;

•the assumed effects of regulations and taxes by governmental agencies;

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

•future improvements in mining technology;

•assumptions governing future prices; and

•future operating costs, including the cost of materials and capital expenditures.

In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a natural gas well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. The cost of purchasing a producing horizontal well could be substantial. Horizontal wells with multiple laterals extending from the well pad may access larger natural gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing natural gas wells or other properties to which we do not hold access, or exclusive access, and are in the path of our coal mining may make mining through those areas uneconomical, thereby effectively causing a loss of significant portions of our coal reserves.

Each of the factors which impacts reserve estimation may vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal reserves.

Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time, we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business and financial condition may be materially adversely affected.

In 2013, Murray Energy and its subsidiaries (“Murray”) entered into a stock purchase agreement (the “Murray sale agreement”) with our former parent, pursuant to which Murray acquired the stock of Consolidation Coal Company and certain subsidiaries and certain other assets and liabilities. At the time of sale, the liabilities included certain retiree medical liabilities under the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) and certain federal black lung liabilities under the Black Lung Benefits Act (“BLBA”).

Murray filed for Chapter 11 bankruptcy in October 2019. As part of the bankruptcy proceedings, Murray unilaterally entered into a settlement with the United Mine Workers of America 1992 Benefit Plan (the “1992 Benefit Plan”) to transfer retirees in the Murray Energy Section 9711 Plan to the 1992 Benefit Plan. This was approved by the bankruptcy court on April 30, 2020. On May 2, 2020, the 1992 Benefit Plan filed an action in the U.S. District Court for the District of Columbia asking the court to make a determination whether the Company’s former parent or the Company has any continuing retiree medical liabilities under the Coal Act (the “1992 Plan Lawsuit”). The Murray sale agreement includes indemnification by Murray with respect to the Coal Act and BLBA liabilities. In addition, the Company had agreed to indemnify its former parent relative to certain pre-separation liabilities. As of September 16, 2020, the Company entered into a settlement agreement with Murray and withdrew its claims in bankruptcy. On September 11, 2020, the defendants in the 1992 Plan Lawsuit filed a Motion to Dismiss Plaintiffs’ Second Amended Complaint which was denied by the Court on March 29, 2022. In October 2025, both parties filed a motion for summary judgment. In the 1992 Benefit Plan’s summary judgment motion, it alleged it is entitled to recover reimbursement for unpaid monthly benefits premiums from the beginning of the lawsuit to present in the amount of $64.8 million, plus interest and damages totaling $25.6 million, as well as an unspecified amount of attorneys’ fees.

Based upon limited information available at the time of the Murray bankruptcy, the Company estimated that the future annual servicing costs of these liabilities in 2026 are approximately $10.0 million, and the annual servicing cost would decline each year since the beneficiaries of the Coal Act consist principally of miners who retired prior to 1994.

Although we separated from our former parent more than eight years ago, we have certain ongoing indemnification obligations related to our separation that could materially impact our financial condition, results of operations and cash flows. Specifically, under the 2017 Separation and Distribution Agreement between the Company and its former parent, we could be required to indemnify our former parent for liabilities relating to our business, whether occurring prior to or after the separation and certain other amounts, including defense costs, settlement amounts and judgments. Likewise, our former parent may fail to indemnify us against certain liabilities related to its business as required by the separation and distribution agreement, or any such indemnity provided by our former parent may be insufficient to make us whole against any third-party claims brought against us in connection with such liabilities.

As of December 31, 2025, our total long-term indebtedness was approximately $459 million, consisting of:

•$106 million under our West Virginia Economic Development Authority (“WVEDA”) 5.45% Solid Waste Disposal Facility Revenue Bonds due March 2035 (“WVEDA Bonds”);

•$103 million under our Maryland Economic Development Corporation (“MEDCO”) 5.00% Port Facilities Refunding Revenue Bonds due March 2035 (“MEDCO Bonds”);

•$98 million under our Pennsylvania Economic Development Financing Authority (“PEDFA”) 5.45% Solid Waste Disposal Facility Revenue Bonds due March 2035 (“PEDFA Bonds,” and together with the WVEDA Bonds and the MEDCO Bonds, the “Series 2025 Bonds”);

•$80 million associated with various equipment financing arrangements;

•$58 million associated with finance leases due through 2030; and

•$14 million of miscellaneous debt.

On January 14, 2025, and in connection with the Merger, we entered into an amendment to our senior secured credit agreement to increase the aggregate revolving commitments from $355 million to $600 million (our “Revolving Credit Facility”). The amendment extended the stated maturity date and provides that, under specified conditions, the maturity of the Revolving Credit Facility may be earlier. At December 31, 2025, no borrowings were outstanding under our Revolving Credit Facility or our trade accounts receivable securitization facility. The degree to which we are leveraged could have important consequences, including, but not limited to:

•increasing our vulnerability to general adverse economic and industry conditions;

•requiring us to dedicate a substantial portion of our cash flow from operating activities to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, share buy-back programs, acquisitions, pay dividends, development of our coal reserves or other general corporate requirements;

•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

•placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and

•limiting our ability to implement our business strategy.

Our senior secured credit agreement and the indentures associated with our Series 2025 Bonds (the “Series 2025 Bonds Indentures”) limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the Series 2025 Bonds Indentures subject us to financial and other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis, including a maximum first lien gross leverage ratio, a maximum total net leverage ratio and a minimum interest coverage ratio, as defined therein. Our senior secured credit agreement and the Series 2025 Bonds Indentures impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the Series 2025 Bonds Indentures restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

We have become increasingly dependent upon digital technologies, including information systems, hardware, software, infrastructure, networks and cloud applications and services (collectively, “IT Systems”) to operate our businesses, process and record financial and operating data, including proprietary and potentially sensitive data (collectively, “Confidential Information”), communicate with our employees and business partners, and estimate quantities of coal reserves, as well as other activities related to our businesses. We own and manage some of these IT Systems but also rely on third parties for a range of IT Systems and related products and services.

We face numerous and evolving cybersecurity risks that threaten the confidentiality, integrity and availability of our IT Systems and Confidential Information, including from diverse threat actors, such as state-sponsored organizations, opportunistic hackers and hacktivists, as well as through diverse attack vectors, such as social engineering, phishing, malware, including ransomware, malfeasance by insiders, human or technological error, and as a result of malicious code embedded in open-source software, or misconfigurations, bugs, or other vulnerabilities in commercial software that is integrated into our IT Systems, products or services, or those of our suppliers or service providers. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber attacks than other targets in the U.S. Deliberate attacks on our IT Systems, or security breaches in our IT Systems, could lead to corruption or loss of our Confidential Information, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Similarly, our vendors or service providers could be the subject of such attacks or breaches that result in the risks of corruption or loss of our Confidential Information and/or the other disruptions as described above.

In addition to the existing risks, the adoption of new technologies, such as artificial intelligence (“AI”), by us, our customers or third parties may also increase our exposure to data breaches or our ability to detect and remediate effects of a breach. Further, as cyber incidents continue to increase in frequency and sophistication, particularly given the increasing availability and sophistication of AI, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. As a result, we may be unable to detect, investigate, remediate or recover from future attacks or incidents, or to avoid a material adverse impact to our IT Systems, Confidential Information or business. There can also be no assurance that our cybersecurity risk management program and processes, including our policies, controls or procedures, will be fully implemented, complied with or effective in protecting our IT Systems and Confidential Information.

Any adverse impact to the availability, integrity or confidentiality of our IT Systems or Confidential Information can result in legal claims or proceedings, regulatory investigations and enforcement actions, fines and penalties, negative reputational impacts that cause us to lose existing or future customers and/or significant incident response, system restoration or remediation and future compliance costs. Any or all of the foregoing could materially adversely affect our business, financial condition and results of operations.

Price adjustment, “price reopener” and other similar provisions in our multi-year coal sales contracts may reduce the protection from coal price volatility traditionally provided by coal supply contracts. Price reopener provisions are present in several of our multi-year coal sales contracts. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our profitability.

Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal quality characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, ash fusion temperature, size consistency and certain metallurgical coal properties. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer.

Our coal sales contracts also typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geological conditions, other natural catastrophes, wars, terrorist acts, civil disturbances or disobedience, strikes, railroad transportation delays caused by a force majeure event and actions or restraints by court order and governmental authority or arbitration award. Depending on the language of 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 and some contracts may oblige us to perform notwithstanding what would typically be a force majeure event.

Our ability to operate our business and implement our strategies depends, in part, on our continued ability to attract and retain the qualified personnel necessary to conduct our business. Efficient coal mining using modern techniques and equipment requires skilled employees in multiple disciplines such as electricians, equipment operators, mechanics, engineers and welders, among others. Although we have not historically encountered shortages for these types of skilled employees, competition in the future may increase for such positions, especially as it relates to the needs of other industries with respect to these positions, including oil and gas. If we experience shortages of skilled employees in the future, our labor and overall productivity or costs could be materially adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employees. If our labor and contractor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially adversely affected.

Except for 39 of our employees at the Core Marine Terminal who unionized in 2018, none of our employees are currently represented by a labor union or covered under a collective bargaining agreement, although many employers in our industry have employees who belong to a union. It is possible that employees at our other locations may join or seek recognition to form a labor union, or we may be required to become a labor agreement signatory. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations with our employees at the Core Marine Terminal, we could potentially experience labor disputes, work stoppages or other disruptions in the business of the Core Marine Terminal, which could negatively impact the profitability of the Core Marine Terminal, and accordingly, have a material adverse effect on our business, results of operations and financial condition.

During the course of the preparation of our financial statements, we evaluate our internal controls to identify and correct deficiencies in our internal control over financial reporting. If we fail to maintain an effective system of disclosure controls or internal control over financial reporting, including satisfaction of the requirements of the Sarbanes-Oxley Act, we may not be able to accurately or timely report on our financial results or adequately identify and reduce fraud. As a result, the financial condition of our business could be adversely affected, current and potential future stockholders could lose confidence in us and/or our reported financial results, which may cause a negative effect on the trading price of our common stock, and we could be exposed to litigation or regulatory proceedings, which may be costly or divert management attention.

The market price of our common stock may fluctuate significantly due to a number of factors, some of which may be beyond our control, including:

•our quarterly or annual earnings, or those of other companies in our industry;

•actual or anticipated fluctuations in our operating results;

•changes in earnings estimates by securities analysts or our ability to meet those estimates or our earnings guidance;

•the operating and stock price performance of other comparable companies;

•overall market fluctuations and domestic and worldwide economic conditions;

•volatility resulting from geopolitical events, inflation, changes in interest rates and other macroeconomic events; and

•other factors described in these “Risk Factors” and elsewhere in this Report.

Stock markets in general have experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the trading price of our common stock. As a result of these factors, holders of our common stock or other securities may not be able to resell their shares at or above the market price at which they purchased their shares or may not be able to resell them at all. In addition, price volatility with our common stock may be greater if trading volume is low.

Furthermore, shares of our common stock are freely tradeable without restriction or further registration under the U.S. Securities Act of 1933, as amended (the “Securities Act”), unless the shares are owned by one of our “affiliates,” as that term is defined in Rule 405 under the Securities Act. As a result, a sale of a substantial amount of our common stock, or the perception that such a sale may take place, could cause our stock price to decline.

The trading market for our shares depends in part on the research and reports that third-party securities analysts publish about our Company and our industry. We may be unable or slow to attract research coverage, and if one or more analysts cease coverage of our Company, we could lose visibility in the market. The impact of the revised EU Markets in Financial Instruments Directive (“MiFID”), which requires that investment managers and investment advisors located in the EU “unbundle” research costs from commissions, may result in fewer securities analysts covering our Company. This is because investment firms subject to MiFID are no longer permitted to pay for research using client commissions or “soft dollars” and instead must pay such costs directly or through a research payment account funded by clients and governed by a budget that is agreed to by the client, thereby raising their costs of providing research coverage. In addition, one or more analysts providing research coverage of our Company could use estimation or valuation methods that we do not agree with, downgrade our shares or issue other negative commentary about our Company or our industry. As a result of one or more of these factors, the trading price of our shares could decline.

The payment and amount of any future dividend following the closing of the Merger is at the discretion of our Board of Directors and will depend upon many factors, including our financial condition and prospects, our capital requirements and access to capital markets, covenants associated with certain of our debt obligations, legal requirements and other factors that our Board of Directors may deem relevant, and there can be no assurance regarding the timing, amount or payment of dividends on our common stock in the future. On February 18, 2025, the Company’s Board of Directors approved a new capital return framework that involves a mix of dividends and share repurchases. The repurchase program permits the repurchase, from time to time, of the Company’s outstanding shares of common stock in an aggregate amount of up to $1 billion, subject to certain covenants under the Revolving Credit Facility and the Series 2025 Bonds Indentures. The repurchase program does not obligate us to repurchase any specific number of shares of common stock and may be suspended from time to time or terminated at any time prior to its expiration. There can be no assurance that we will repurchase shares under the repurchase program in the future in any particular amounts or at all. A reduction in, or elimination of, share repurchases could have a negative effect on the trading price of our common stock.

Your percentage of ownership in us may be diluted because of equity issuances for future acquisitions, capital market transactions or otherwise, including, without limitation, equity awards that we may be granting to our directors, officers and employees. We cannot predict the effect, if any, that market sales of these securities or the availability of the securities will have on the prevailing market price of our common stock. Substantial sales of shares of our common stock or other securities into the public market, or the perception that those sales could occur, may cause the market price of our common stock to decline. Future issuances of our common stock, or other securities convertible into our common stock, may result in significant dilution to the proportionate ownership and voting power of our existing stockholders and could have a dilutive effect on our earnings per share, which could adversely affect the market price of our common stock.

It is anticipated that the compensation committee of the Board of Directors of the Company will continue to grant additional equity awards to Company employees and directors, from time to time, under the Company’s compensation and employee benefit plans. These additional awards will have a dilutive effect on the Company’s earnings per share, which could adversely affect the market price of the Company’s common stock.

In addition, our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock, often called “blank check preferred stock,” having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock with respect to dividends and distributions, as our Board of Directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock.

For example, we could grant the holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.

The Company’s amended and restated certificate of incorporation and amended and restated bylaws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the bidder and to encourage prospective acquirers to negotiate with the Company’s Board of Directors rather than to attempt a hostile takeover. These provisions include, among others:

•the inability of our stockholders to act by written consent unless such written consent is unanimous;

•the inability of our stockholders to call special meetings;

•rules regarding how stockholders may present proposals or nominate directors for election at stockholder meetings;

•the right of our Board of Directors to issue preferred stock without stockholder approval; and

•the ability of our directors, and not stockholders, to fill vacancies (including those resulting from an enlargement of our Board of Directors) on our Board of Directors.

In addition, we are subject to Section 203 of the Delaware General Corporation Law (“DGCL”). Section 203 provides that, subject to limited exceptions, persons that (without prior board approval) acquire, or are affiliated with a person that acquires, more than 15% of the outstanding voting stock of a Delaware corporation shall not engage in any business combination with that corporation, including by merger, consolidation or acquisitions of additional shares, for a three-year period following the date on which that person or its affiliate becomes the holder of more than 15% of the corporation’s outstanding voting stock.

We believe these provisions will protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our Board of Directors and by providing our Board of Directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions could have the effect of delaying, deferring or preventing a change in control or the removal of the existing Board of Directors and/or management, of deterring potential acquirers from making an offer to our stockholders and of limiting any opportunity to realize premiums over prevailing market prices for our common stock in connection therewith. This could be the case, notwithstanding the fact that a majority of our stockholders might benefit from such a change in control or offer.

Our certificate of incorporation designates the State Courts of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain an alternative judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, a state court sitting in the State of Delaware (or, if no state court located within the State of Delaware has jurisdiction, the federal court for the District of Delaware) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

•any derivative action or proceeding brought on our behalf;

•any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

•any action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws;

•any action asserting a claim that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein; or

•any action asserting an internal corporate claim as defined in Section 115 of the DGCL.

Any person or entity purchasing or otherwise holding any interest in shares of our common stock will be deemed to have received notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

The Company depends on the experience and industry knowledge of its officers and other key employees to execute its business plans. The success of the Company will depend in part on its ability to retain key management personnel and other key employees. Employees of the Company may experience uncertainty about their roles within the Company following the Merger or other concerns regarding the operations of the Company following the Merger, any of which may have an adverse effect on the ability of the Company to retain key management and other key personnel. If the Company is unable to retain personnel, including key management, who are critical to the future operations of the Company, the Company could face disruptions in its operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key personnel could diminish the anticipated benefits of the Merger. No assurance can be given that the Company will be able to retain key management personnel and other key employees to the same extent that the Company has previously been able to retain its employees.

Parties with which the Company does business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with the Company. The Company’s business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom they do business may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than the Company. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations of the Company, as well as a material and adverse effect on the Company’s ability to realize the expected cost savings and other benefits of the Merger.

The Company has incurred a number of non-recurring costs associated with negotiating and completing the Merger and combining Arch’s operations with the Company’s operations, and the Company expects to continue to incur a number of non-recurring costs. These expenses have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs, filing fees and debt restructuring costs.

The Company will also incur transaction costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and employment-related costs. Expectations that the Company will offset integration-related costs over time by the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not be achieved in the near term, or at all. The costs described above, as well as other unanticipated costs and expenses, could adversely affect the financial condition, cash flows and operating results of the Company.

Prior to the completion of the Merger, Arch operated independently from the Company. Following the completion of the Merger, their respective businesses may not be integrated successfully. It is possible that the integration process could result in the loss of key employees; the loss of customers, service providers, vendors or other business counterparties; the disruption of ongoing businesses; inconsistencies in standards, controls, procedures and policies; potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with and following completion of the Merger; or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.

In addition, at times the attention of certain members of management and resources may be focused on completion of the Merger and the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may be beneficial, which may disrupt each company’s ongoing operations and the operations of the Company.

Furthermore, the Board of Directors and executive leadership of the Company consists of former directors from each of the Company and Arch and former executive officers from each of the Company and Arch. Combining the boards of directors and management teams of each company into a single board and a single management team could require the reconciliation of differing priorities and philosophies.

The success of the Merger will depend, in part, on the Company’s ability to realize the anticipated benefits and cost savings from combining the Company’s and Arch’s businesses and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, or could have other adverse effects that the Company does not currently foresee, in which case, among other things, the Merger may not be accretive to free cash flow and may not generate significant discretionary cash flow to return to stockholders via share repurchases or other means. Some of the assumptions that the Company has made, such as the achievement of the anticipated benefits related to the geographic, commodity and asset diversification and the expected size, scale, inventory and financial strength of the Company, may not be realized. The integration process may result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact the Company.

Additionally, certain operations may not realize the full potential that we anticipated at the Merger due to operational issues we have faced, including at our Leer South and West Elk locations in 2025. The Leer South longwall system had been idle since January 13, 2025, when combustion-related activity was detected in a previously mined area. In addition, our West Elk longwall mine in Colorado experienced a period of transition associated with its move to the B-Seam in the fourth quarter of 2025.

As of December 31, 2025, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $717.3 million, $112.6 million of which is subject to expiration, if not utilized, starting in 2037. The remaining carryforwards do not expire; however, they can only be used to offset 80% of U.S. federal taxable income in any taxable year. The Company’s ability to utilize these NOLs and other tax attributes to reduce future taxable income depends on many factors, including its future income, which cannot be assured. Section 382 of the Internal Revenue Code (“Section 382”) and Section 383 of the Internal Revenue Code generally impose an annual limitation on the amount of NOLs and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). The Merger was deemed an ownership change and, as a result, utilization of these NOLs is subject to an annual limitation under Section 382, determined by multiplying (1) the fair market value of its stock at the time of the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs, subject to certain adjustments. Any unused annual limitation may be carried over to later years.

None.

The Company has a cybersecurity risk program that is designed to align with industry standards and best practices, managed by a dedicated staff and specialists. This does not imply that we meet any particular technical standards, specifications or requirements, only that we use industry standards and best practices as a guide to help us identify, assess and manage cybersecurity risks relevant to our business. We have implemented a set of system, network and application-level controls designed to protect our corporate data and systems. These controls are monitored for cybersecurity risk events and incidents on a continuous basis by a dedicated staff of cybersecurity professionals and various third-party providers. These controls are updated as the Company deems necessary to protect the Company. In addition, the Company also takes a proactive approach by monitoring cybersecurity threat intelligence to stay informed regarding emerging risks.

The cybersecurity risk program also utilizes third-party assessors, consultants and auditors to perform various services, such as tabletop exercises and network penetration tests. The Company provides awareness training to its employees to help identify, avoid and mitigate cybersecurity threats. Employees with network access are required to participate in required training quarterly, including spear phishing and other awareness training. The program also has a policy in place related to the use of vendors and third-party risk. Cybersecurity risk is also evaluated during the acquisition process for new products and services.

The Company accounts for cybersecurity risk as a part of the Company’s overall business strategy and planning. The Audit Committee of the Company’s Board of Directors, which oversees all matters related to risk management and, in particular, the security of and risks related to the Company’s IT Systems, receives regular reports on the Company’s cybersecurity risk management efforts from various senior officers of the Company. The Company also has a corporate cybersecurity risk Steering Committee, which is a cross-functional group comprised of both senior management and other key business unit leaders that provides input to senior management on the Company’s cybersecurity risk program.

The Company has not experienced any material operational or financial impact as the result of a cybersecurity risk or incident, and, at this time, the Company has not identified risks from cybersecurity threats, including as a result of any prior cybersecurity incidents, that are reasonably likely to materially affect the Company’s business strategy, results of operations or financial condition. However, the Company faces risks from cybersecurity threats that, if realized, are reasonably likely to materially affect the Company, including its operations, business strategy, results of operations or financial condition, and it is prepared to mitigate and respond to such an event should it occur. The Company has prepared a Cybersecurity Incident Response Plan, as well as an Information Technology Disaster Recovery Plan. These plans are reviewed, updated and tested on a regular basis. Specifically, the Company conducts cybersecurity tabletop exercises that include participation by Audit Committee members, senior management and third-party cybersecurity consultants.

The Company faces a range of cybersecurity threats, including threats common to many industries such as ransomware and denial of service, as well as more advanced threats specific to critical infrastructure industries such as mining. The Company’s customers, equipment suppliers, transportation facility providers and joint venture partners face similar cybersecurity threats, and a cybersecurity incident affecting the Company or any of these entities could materially affect our operations, performance and results of operations. For more information regarding the risks we face from cybersecurity, please see the section titled “Risk Factors - Terrorist attacks or cyber incidents could result in information theft, data corruption, operational disruption and/or financial loss.”

The Company’s Board of Directors has assigned oversight of cybersecurity risk to the Audit Committee, as outlined in the Audit Committee’s charter. Updates on the cybersecurity risk program are provided at each Audit Committee meeting. Additionally, the Company’s senior management engages with the Audit Committee on a regular basis to provide updates on our cybersecurity risk program.

The Company has a Director of Cybersecurity who reports directly to the Director of Information Technology and is primarily responsible for assessing and managing material risks from cybersecurity threats. The Company’s Director of Cybersecurity has 25 years of industry experience and holds many relevant industry certifications. The Director of Cybersecurity has direct oversight of the cybersecurity risk program. Cybersecurity risk briefings are provided to the Audit Committee by the Director of Information Technology at all regular meetings. Additionally, the Director of Information Technology and Director of Cybersecurity communicate directly with the Audit Committee chair as needed to ensure adequate oversight of the program.

The Company’s management team takes steps to stay informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, including external consultants engaged by the Company and alerts and reports produced by security tools deployed in the Company’s information technology environment.

See “Principal Properties” in Item 1 of this Report for a description of our mining properties and our terminals through which we provide coal and export terminal services, incorporated herein by this reference. See the map under “Principal Properties” in Item 1 of this Report for the location of the Company’s material properties. Our principal executive offices are located at 275 Technology Drive, Suite 101, Canonsburg, Pennsylvania 15317-9565.

Our operations are subject to a variety of risks and disputes normally incidental to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are not currently subject to any material litigation other than those described in Note 22—Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Report, which descriptions are incorporated herein by this reference.

SEC regulations require us to disclose certain information about environmental proceedings if we reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. We use a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required, as permitted pursuant to Item 103(c)(3)(iii) of Regulation S-K. No such environmental proceedings were pending or contemplated as of December 31, 2025.

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

Shares of the Company’s common stock are listed on the New York Stock Exchange and trade under the symbol “CNR” since January 15, 2025. Trading of the Company’s common stock began as “when-issued” trading on November 3, 2017 and began as “regular-way” trading on November 29, 2017, under the ticker symbol CEIX.

As of January 30, 2026, there were 66 holders of record of our common stock. A substantially greater number of holders of our common stock are “street name” or beneficial holders, whose shares of record are held by banks, brokers and other financial institutions.

The following performance graph compares the Company’s cumulative total shareholder return to that of the Company’s peer group and the Standard & Poor’s 500 Stock Index. The peer group, for the purposes of the information presented below, is comprised of Alliance Resource Partners LP, Alpha Metallurgical Resources, Inc., Hallador Energy Company, Peabody Energy Corporation, Ramaco Resources, Inc. and Warrior Met Coal, Inc. Our peer group was updated for 2025 to remove Arch in light of the Merger with the Company in January 2025.

The graph above assumes that the value of an initial investment in the Company’s common stock and each index was $100 at December 31, 2020. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2025.

The information above is being furnished pursuant to Item 201(e) of Regulation S-K.

The following table sets forth repurchases of shares of the Company's common stock during the three months ended December 31, 2025:

(a) On February 18, 2025, the Company's Board of Directors approved a capital return framework that involves a mix of dividends and share repurchases. The repurchase program permits the repurchase, from time to time, of the Company's outstanding shares of common stock in an aggregate amount of up to $1 billion, subject to certain covenants in the Revolving Credit Facility and the Series 2025 Bonds Indentures that limit the Company's ability to repurchase shares of its common stock. The repurchases will be effected from time to time on the open market, in privately negotiated transactions or under a Rule 10b5-1 plan. The program does not obligate the Company to acquire any particular amount of its common stock, and the program can be modified or suspended at any time at the Company's discretion.

(b) Management cannot estimate the number of shares that will be repurchased because purchases are made based upon the Company's stock price, the Company's financial outlook and alternative investment options.

(c) In the three months ended December 31, 2025, the Company utilized approximately $22 million to repurchase shares of its common stock.

The declaration and payment of dividends by the Company is at the discretion of the Company’s Board of Directors. The Revolving Credit Facility and the Series 2025 Bonds Indentures include certain covenants limiting the Company’s ability to declare and pay dividends. See “Total Equity and Dividends” in Item 7 of this Report for additional information.

See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to our equity compensation plans.

On January 14, 2025, the Company completed the Merger with Arch. Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Arch, with Arch continuing as the surviving corporation and as a wholly-owned subsidiary of the Company. See Note 2—Merger with Arch in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Report for additional information.

Prior to the completion of the Merger, the Company consisted of two reportable segments, the PAMC segment and the Core Marine Terminal segment. Following completion of the Merger, the Company adjusted its internal reporting structure, and the Company’s chief operating decision maker (“CODM”) changed the manner in which he measures financial performance and allocates resources. Thus, the Company reassessed its reporting segments, and the Company now consists of four reportable segments: (1) the High CV Thermal segment; (2) the Metallurgical segment; (3) the Powder River Basin (“PRB”) segment; and (4) the Core Marine Terminal segment. Accordingly, the manner in which the Company reports its operations has been changed retrospectively, and all relevant prior period amounts have been recast to reflect this change.

On January 13, 2025, a combustion-related activity was reported at the Leer South mine, located in Barbour County, West Virginia. The Company temporarily sealed the Leer South mine’s active longwall panel in order to extinguish such activity. The Company resumed development work with continuous miners in February 2025, and Company personnel and regulatory officials re-entered the sealed area of the mine on June 10, 2025. Thereafter, ventilation to the full mine was re-established, hydraulic pressure along the longwall face was restored and an extensive evaluation of the mine’s major equipment and infrastructure was conducted. As expected, the longwall suffered insignificant damage by the combustion event, and major components and systems remain in good condition. On June 26, 2025, the operating team found it necessary to evacuate the mine again and begin restoring pumpable seals to the affected area in the wake of an increase in carbon monoxide levels. In December 2025, the Company recovered the major longwall mining equipment, repositioned it and resumed longwall operations. Following the repositioning, the Company permanently sealed the affected area.

The Company incurred fire extinguishment and idle costs of $101 million at Leer South in 2025 for which it is pursuing recoveries under its relevant insurance policies. The Company’s initial advancement of insurance proceeds was $19.4 million. The Company will continue to pursue all avenues for additional recoveries.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law by the President of the U.S. Several provisions included in the OBBBA are expected to benefit the Company, including language designating U.S.-produced metallurgical coal as a “critical material” under Internal Revenue Code Section 45X (Advanced Manufacturing Production Credit), through which the Company will be eligible for a 2.5% monetizable tax credit on production-related costs beginning in 2026 and sunsetting at the end of 2029. The Company is currently evaluating the OBBBA provisions, and the determination as to the applicability and extent of the OBBBA’s provisions on the Company’s future results of operations and cash flows will be dependent upon interpretations of the law and revenue rulings issued by the U.S. Treasury Department.

President Trump issued a series of executive orders in April 2025 intended to reduce the regulatory burden on U.S. coal-based power plants and to ensure the long-term preservation of the U.S. coal fleet. The Trump Administration views the coal fleet as essential to the security, resilience and reliability of the U.S. power system. Reduction of regulatory burden allows for any impediments to domestic thermal coal demand to be challenged and possibly removed so that the Company could have an increased chance to sell more of its thermal coals specifically within the U.S. The executive orders help to further de-risk the domestic thermal market in the near term.

Our management team uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability. The metrics include: (i) coal production and sales volumes; (ii) realized coal revenue, a non-GAAP financial measure; (iii) realized coal revenue per ton sold, an operating ratio derived from non-GAAP financial measures; (iv) cash cost of coal sold, a non-GAAP financial measure; (v) cash cost of coal sold per ton, an operating ratio derived from non-GAAP financial measures; (vi) cash margin per ton sold, an operating ratio derived from non-GAAP financial measures, defined as realized coal revenue per ton sold less cash cost of coal sold per ton; and (vii) adjusted EBITDA, a non-GAAP financial measure.

We believe that realized coal revenue and realized coal revenue per ton sold better reflect our revenue for the quality of coal sold and our operating results by including all income from coal sales. We believe cash cost of coal sold, cash cost of coal sold per ton and cash margin per ton sold normalize the volatility contained within comparable measures prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) by adjusting for certain non-operating or non-cash transactions. We believe that adjusted EBITDA provides a helpful measure of comparing our operating performance with the performance of other companies that have different financing, capital structures and tax rates than ours.

Each of these non-GAAP measures are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

•our operating performance compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis, tax rates or capital structure;

•the ability of our assets to generate sufficient cash flow;

•our ability to incur and service debt and fund capital expenditures;

•the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities; and

•the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

These non-GAAP financial measures should not be considered an alternative to revenues, cost of sales, net income (loss) or any other measure of financial performance presented in accordance with GAAP. These measures exclude some, but not all, items that affect measures presented in accordance with GAAP, and these measures and the way we calculate them may vary from those of other companies. As a result, the items presented below may not be comparable to similarly titled measures of other companies.

We define realized coal revenue as revenues reported in the Consolidated Statements of (Loss) Income less transportation costs, transloading revenues and other revenues not directly attributable to coal sales. We define realized coal revenue per ton sold as realized coal revenue divided by tons sold. The following tables present reconciliations by reportable segment of realized coal revenue and realized coal revenue per ton sold to revenues, the most directly comparable GAAP financial measure (in thousands, except per ton information):

The following table presents a breakdown of the realized coal revenue per ton sold for the metallurgical segment between coking coal and thermal byproduct (in thousands, except per ton information):