Core Natural Resources Inc

General

We are a world-class producer and exporter of high-quality, low-cost coals, including metallurgical and thermal coals. With a focus on seaborne markets, we play an essential role in meeting the world's growing need for steel, infrastructure and energy, and have ownership interests in two marine export 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.

On January 14, 2025, Core Natural Resources, Inc. (formerly known as CONSOL Energy Inc.), a Delaware corporation, completed its previously announced all-stock merger of equals transaction with Arch pursuant to the Merger Agreement. 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 athttp://www.corenaturalresources.com/. The information contained in or connected to the website will not be deemed to be incorporated in this document, and you should not rely on any such information in making an investment decision.

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

Our Mission

The Company's mission is to become the world's leading provider of essential coal-based natural resources in support of human progress. We are committed to providing essential coal-based products necessary for infrastructure development, urbanization, transportation and reliable and affordable 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. In doing so, 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, sustainability, and continuous improvement 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 these values, will allow management to create value for the long-term. We believe that the use of coal in industrial applications, including but not limited to the steel-making process, and as a fuel source for electricity will continue for many years.

Our Strategy

Following the Merger, the Company’s near-term strategy is focused on promptly and effectively integrating historic Arch with CONSOL Energy's business, assets and employees. The integration is expected to deliver future annual cost savings and synergies to the Company and its stockholders.

At the same time, 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 buybacks and/or dividends and, when prudent, allocating capital toward compelling growth and diversification 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. Following the Merger, 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. The Company believes that the Merger will provide ongoing cash generation through a strong contracted thermal coal position from the PAMC coupled with meaningful opportunities through Arch’s metallurgical coal platform. Through this, the Company has the potential to return significant capital to stockholders while simultaneously making strategic investments in innovation and growth.

Opportunistically grow our presence in the industrial and metallurgical markets, while preserving coal sales to rail-served power plants in strategic market areas

We plan to minimize our market risk and maximize realizations by continuing to focus on placing a growing portion of our production in the export markets, where we sell to industrial, metallurgical and power generation end-users. This approach provides us pricing upside when markets are strong and with volume stability when markets are weak.

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. Through the Merger, we spring-boarded our plan to minimize market risk and maximize realizations via the combination of complementary coal types and increased access to the seaborne markets. Following the Merger, 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. The Company believes that the Merger will provide ongoing cash generation through a strong contracted thermal coal position from the PAMC coupled with meaningful opportunities through Arch’s metallurgical coal platform.

Drive operational excellence through safety, compliance, and continuous improvement

We continue to focus on our values of safety, sustainability and continuous improvement. Historically, the PAMC has been one of the most productive, lowest-cost underground mines in the coal industry, while simultaneously setting some of the industry’s highest standards for safety and compliance. Over the past five years, our PAMC Mine Safety and Health Administration (“MSHA”) total reportable incident rate was approximately 53% lower than the national average underground bituminous coal mine incident rate. Furthermore, the PAMC MSHA significant and substantial (“S&S”) citation rate per 100 inspection hours was approximately 79% lower than the industry’s average MSHA S&S citation rate over the twelve-month period ended December 31, 2024. Prior to the Merger, Arch was also viewed as a demonstrated leader in mine safety, with an average lost-time incident rate during the past five years that was more than 2.5 times better than the industry average.

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. Consistent with our core value of continuous improvement, productivity at the PAMC has improved from 6.27 tons per employee hour in 2015 to 7.34 tons per employee hour in 2024. We intend to continue to grow the economic competitiveness of our operations by proactively identifying, pursuing and implementing efficiency improvements and new technologies that can drive down unit costs without compromising safety or compliance.

Preserve and Increase Cash Generation

The Company has generated significant cash from operations since becoming a publicly-traded company. We believe that the Merger further positions the Company to continue to generate significant cash from operations 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.

Maintain Liquidity and Ability to Access Capital Markets

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

The Company and Arch historically have successfully accessed the municipal bond markets, and the Company expects to continue to be able to access these markets following the Merger.

In addition, on January 14, 2025, and in connection with the Merger, the Company entered into an amendment to its existing revolving credit facility. The amendment increases the available revolving commitments from $355 million to $600 million and extends the maturity date of the facility to April 30, 2029. The revolving credit facility now includes participation from 22 banks, including nine new lenders, and 37% of the total commitments come from new lenders, while 63% are from existing lenders. Additionally, the Company reduced the annual interest rate by 75 bps while further enhancing financial flexibility.

Also, 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.

Selectively grow our business to maximize stockholder value by capitalizing on synergies with our assets and expertise

We plan to judiciously direct the cash generated by our operations toward those opportunities that present the greatest potential for value creation to our stockholders, particularly those that take advantage of synergies with our asset base and/or the expertise of our management team. To that end, we intend to regularly and rigorously 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 assets and, we believe, is well qualified to evaluate organic and external growth opportunities. We plan to carefully weigh any capital investment decisions against alternate uses of the cash to help ensure we are delivering the most value to our stockholders.

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, 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 electrode materials. 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.

We also continue to partner with Ohio University, the U.S. Department of Energy and certain other industry partners on several projects to develop coal-derived materials that can potentially be used in applications such as engineered composite building materials and three-dimensional printing. Another initiative, our 21st Century Power Plant project, is also receiving funding from the Department of Energy to evaluate a next-generation power plant that would be fueled by waste coal and biomass and equipped with carbon dioxide (CO 2) capture and storage to achieve net neutral or negative CO 2 emissions. In addition, our Department of Energy-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.

From time to time, we also evaluate investments in industries and sectors that are not related to coal but may provide long-term business opportunities that develop due to the potential energy transition efforts of various local, federal and international governments.

Our Competitive Strengths

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

Focus on free cash flow generation supported by strong margins and optimized production levels

We intend to continue our focus on maintaining high margins by optimizing production from our high-quality reserves and leveraging our extensive logistics infrastructure and broad market reach. Following the Merger, the Company has broad and diverse assets that produce coal with qualities and blends capable of serving multiple growth markets and geographies. Following the Merger, 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. The Company believes that the Merger will provide ongoing cash generation through a strong contracted thermal coal position from the PAMC coupled with meaningful opportunities through Arch’s metallurgical coal platform.

For example, the PAMC’s low-cost structure, high-quality product, favorable access to rail and port infrastructure and diverse base of end-use customers allow it to move large volumes of coal at positive cash margins throughout a variety of market conditions. Additionally, the Leer franchise consistently ranks among the lowest cost U.S. metallurgical mines and produces a product quality that is recognized and sought-after worldwide. The Leer and Leer South operations are complemented by the Beckley and Mountain Laurel continuous miner mines, which in aggregate provide us with a full suite of high-quality metallurgical products for sale into the global metallurgical market. Additionally, the location of Arch’s mines enables us to ship coal to most of the major coal-fueled power plants in the United States. 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.

Extensive, High-Quality Reserve Base

The PAMC has extensive high-quality reserves of bituminous coal. We mine our reserves from the Pittsburgh No. 8 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2024, the PAMC included 557.6 million tons of recoverable coal reserves that are sufficient to support approximately 20 years of full-capacity production. The advantageous qualities of our coal enable us to compete for demand from a broader range of the global industrial and power generation markets. In addition to the substantial reserve base associated with the PAMC, our Itmann Mining Complex includes 27.5 million tons of recoverable coal reserves that are sufficient to support more than 30 years of full-capacity production, and our 1.3 billion tons of Greenfield Reserves and Resources in the Northern Appalachian Basin (“NAPP”), the Central Appalachian Basin (“CAPP”) and the Illinois Basin (“ILB”) feature both thermal and metallurgical reserves and resources and provide additional optionality for organic growth or monetization as market conditions allow.

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

Based on production per employee, the PAMC is a productive and efficient coal mining complex in NAPP, averaging 7.37 tons of coal production per employee hour for the past two years. 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 and Leer South longwall mines that we acquired through the Merger anchor our large-scale, first quartile metallurgical franchise. The Leer franchise consistently ranks among the lowest cost U.S. metallurgical mines and produces a product quality that is recognized and sought-after worldwide.

Strategically Located Mining Operations with Advanced Distribution Capabilities and Excellent Access to Key Logistics Infrastructure

Our logistics infrastructure and proximity to coal-fired power plants in the eastern United States provides us with operational and marketing flexibility, reduces the cost to deliver coal to our core markets and allows us to realize higher free-on-board (“FOB”) mine prices. We believe that we have a significant transportation cost advantage compared to many of our competitors, particularly producers in the ILB and the Powder River Basin (“PRB”), for deliveries to customers in our core markets and to East Coast ports for international shipping. For example, based on publicly available data and internal estimates, we believe that the transportation cost advantage from our mines compared to ILB mines (not accounting for Btu differences) is approximately $5 to $8 per ton for coal delivered to foreign consumers in Europe and India, and an even more pronounced cost advantage for coal delivered to domestic customers in the mid-Atlantic states. Our ability to accommodate multiple unit trains from both Norfolk Southern Corporation (“Norfolk Southern”) and CSX Transportation Inc. (“CSX”) at the Central Preparation Plant, which includes a dual-batch loadout facility capable of loading up to 9,000 tons of clean coal per hour and 19.3 miles of track with three sidings, allows for the seamless transition of locomotives from empty inbound trains to fully loaded outbound trains at our facility. Furthermore, the PAMC has exceptional access to export infrastructure in the United States. Through our 100%-owned CONSOL Marine Terminal, served by both the Norfolk Southern and CSX railroads, the PAMC and the Itmann Mining Complex have a competitive advantage in the world’s seaborne coal markets. As a result of the Merger, we now have access to a second East Coast terminal, which provides opportunistic flexibility for all of Core's eastern operations, including the Leer, Leer South, Beckley and Mountain Laurel mines, to further enhance our competitive advantage in the world's seaborne coal markets.

Strong, Well-Established Customer Base Supporting Contractual Volumes

We have a well-established and diverse customer base, comprised of export industrial customers, metallurgical end-users and domestic 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 92% of our sales in 2024 were to customer companies that were in our 2023 portfolio, and six of our top domestic power plant customers in 2024 (which are included in the ten plants to which we shipped approximately 500,000 tons or more of PAMC coal in 2024) have been in our portfolio for at least five consecutive years. In addition, to mitigate our exposure to coal-fired power plant retirements, we have strategically developed our customer base to include power plants that are economically positioned to continue operating for the foreseeable future and that are equipped with state-of-the-art environmental controls.

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 from 8.3 million tons (or approximately 32% of our annual sales volume) in 2017 to 15.9 million tons (or approximately 57% of our annual sales volume) in 2024, including sales from both the PAMC and the Itmann Mining Complex.

Similarly, prior to the Merger, Arch marketed its metallurgical and thermal coal to domestic and foreign steel producers, domestic and foreign 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. Additionally, in 2024, Arch sold coal to domestic customers located in 25 different states as the location of its mines enabled it to ship coal to most of the major coal-fueled power plants in the United States and exported coal to Europe, Asia, Central and South America, and Africa.

Highly Experienced Management Team and Operating Team

The Company is being led by a proven and highly experienced management team that reflects the strengths and capabilities of both companies. Our management team is overseen by an experienced, diverse and majority-independent board of directors, comprised of eight directors – four former directors of the Company board immediately prior to the Merger and four former directors of the Arch board immediately prior to the Merger. 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 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 cycle. 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.

Principal Properties

Prior to the Merger, our most significant tangible assets were the PAMC and the CONSOL Marine Terminal. The PAMC and the CONSOL Marine Terminal have consistently generated strong free cash flows. As of December 31, 2024, the PAMC controlled 557.6 million tons of high-quality Pittsburgh seam reserves, enough to allow for an equivalent of approximately 20 years of full-capacity production. As of December 31, 2024, the Itmann Mining Complex included 27.5 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. In addition, as of December 31, 2024, we owned or controlled approximately 1.3 billion tons of Greenfield Reserves and Resources, portions of which are located in the NAPP, CAPP and ILB.

As a result of the Merger, our presence in the metallurgical coal market has expanded with two longwall mines, Leer and Leer South, in West Virginia, and two continuous miner mines, Beckley and Mountain Laurel, in West Virginia. These mines produce a premium metallurgical product used in the global steel industry. Through the Merger, we also gained thermal mines, Black Thunder and Coal Creek, in the PRB, as well as West Elk, in Colorado. The PRB mines produce thermal coal for sale into international and domestic markets. The West Elk mine in Colorado produces 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, DTA, on the U.S. Eastern seaboard, as well as strategic connectivity to ports on the West Coast and the Gulf of Mexico.

Through the Merger, we have created a global leader exceptionally well-positioned to compete and succeed in two significant, high-potential market segments – the global metallurgical and global high-rank thermal coal markets.

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

Thermal Mining Properties

Our active thermal mines are described below.

•Pennsylvania Mining Complex: The PAMC includes the Bailey Mine, the Enlow Fork Mine, the Harvey Mine 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 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 our 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 base of diverse and strategically selected industrial and metallurgical end users in the United States and globally. 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 CONSOL Marine Terminal. We also continue to support power plant customers in the eastern United States and abroad.

•Black Thunder: Black Thunder is a surface mining complex located on approximately 35,300 acres in Campbell County, Wyoming. The Black Thunder complex extracts thermal coal from the Upper Wyodak and Main Wyodak seams. We control a significant portion of the coal reserves through federal and state leases. The Black Thunder mining complex had approximately 378.0 million tons of proven and probable reserves at December 31, 2024. The Black Thunder mining complex currently consists of four active pit areas and two active loadout facilities. 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: Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. The Coal Creek mining complex extracts thermal coal from the Wyodak-R1 and Wyodak-R3 seams. The Coal Creek complex currently consists of one active pit area and a loadout facility. 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 is located on approximately 18,400 acres in Gunnison County, Colorado. The West Elk mining complex extracts thermal coal from the E seam. We control a significant portion of the coal reserves through federal and state leases. The West Elk mining complex had approximately 34.5 million tons of proven and probable reserves at December 31, 2024. The West Elk complex currently consists of a longwall, continuous miner sections, a preparation plant, and a loadout facility. We ship most of the coal raw to our customers via the Union Pacific railroad. When required to improve the quality of some of our coal production, it is processed through the 800 ton-per-hour preparation plant. The loadout facility can load an 11,000-ton train in less than three hours.

Metallurgical Mining Properties

Our active metallurgical mines are described below.

•Leer: The Leer complex is a longwall operation, located in Taylor County, West Virginia, that includes approximately 33.0 million tons of proven and probable coal reserves as of December 31, 2024 that are primarily sold as High-Vol A metallurgical quality coal from the Lower Kittanning seam, and are part of approximately 93,200 acres that is considered our Tygart Valley area. A significant portion of the reserves at Leer are owned rather than leased from third parties. All the 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 is a longwall operation in the Lower Kittanning seam with a preparation plant and a loadout facility located on approximately 26,500 acres in Barbour County, West Virginia. 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. Coal quality is primarily High-Vol A metallurgical coal similar to our Leer Complex. The Leer South mining complex had approximately 60.6 million tons of proven and probable reserves at December 31, 2024. A significant portion of the reserves at Leer South are owned rather than leased from third parties.

•Beckley: The Beckley mining complex is located on approximately 14,700 acres in Raleigh County, West Virginia. Beckley is extracting high quality, Low-Vol metallurgical coal in the Pocahontas No. 3 seam. The Beckley mining complex had approximately 24.7 million tons of proven and probable reserves at December 31, 2024. 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 38,200 acres in Logan County and Boone County, West Virginia. Underground mining operations at the Mountain Laurel mining complex extract High-Vol B metallurgical coal from the Alma and No. 2 Gas seams. 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 Mining Complex: The Itmann No. 5 Mine is located in Wyoming County, West Virginia. The Company controls approximately 20,224 contiguous acres of mining rights, by ownership or lease, to the Pocahontas 3 seam and the Pocahontas 4 seam. The Itmann Mining Complex had approximately 27.5 million tons of proven and probable coal reserves at December 31, 2024. The preparation plant includes a rail loadout located on the Guyandotte Class I rail line, which can be served by both Norfolk Southern and CSX, and has the capability for processing up to an additional 750 thousand to 1 million saleable tons annually from third-parties and mining of our surrounding reserves. This additional processing revenue provides an avenue of growth for the Company.

Terminals

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

•CONSOL Marine Terminal: Through our wholly-owned subsidiary, CONSOL 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 United States coal terminal served by two Class I railroads, Norfolk Southern and CSX. In 2024, approximately 17.0 million tons of coal were shipped through the CONSOL Marine Terminal. Approximately 84% of the tonnage shipped was produced by the Pennsylvania Mining Complex. The CONSOL Marine Terminal has storage capacity of 1.1 million tons with more than thirty acres of capacity for stockpiles. The facility possesses blending capabilities, and it has transloaded approximately 14.7 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, as well as domestic coal users located along the Atlantic coast of the United States. From time to time, we may lease a portion of our port capacity to third parties.

Non-Core Coal Assets and Surface Properties

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

Mining Properties as of December 31, 2024

Information concerning our mining properties in this Annual Report on Form 10-K 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 Annual Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. 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 coal resources are estimated internally by professionals whom we believe to be competent, including engineers and geologists. These estimates are based on geologic data, coal ownership information and current and/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 geologic 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 coal resources, and supporting information, have been assessed by the John T. Boyd Company, a qualified person firm, which conforms to our requirements under subpart 1300 of Regulation S-K for qualified persons.

The information that follows relating to our individually material property – PAMC – 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 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 our 2024 Annual Report on Form 10-K.

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 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. Recoverable coal reserves and 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 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, 2024:

SUMMARY MATERIAL COAL RESERVES AT END OF THE

SUMMARY NON-MATERIAL COAL RESERVES AT END OF THE

SUMMARY COAL RESOURCES AT END OF THE

Note: All resource tons in the table above are reported as clean recoverable tons.

The following table classifies the Company's coal by type (thermal versus metallurgical). The table also classifies metallurgical coal as high, medium and low volatile, which is based on volatile matter content.

Recoverable Coal Reserves and Coal Resources

by Product (in Millions of Tons) as of December 31, 2024

Internal Controls Disclosure

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

Records from exploration drilling completed on the mining properties comprise the primary data used in the evaluation of the coal resources for each property. The Company maintains written field and exploration guidelines that cover standard procedures, including site safety, mapping, and how to select proper drilling equipment, record accurate and detailed geological logs, perform coal sampling, supervise geophysical logging, and plug drill holes once work was 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 is 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 pick up by the selected independent lab that will perform the required analyses. All analytical work is conducted to International Organization for Standardization or ASTM International standards.

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

Pennsylvania Mining Complex - Material Reserves

Pennsylvania Mining Complex. The Pennsylvania Mining Complex 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 179,028 acres of mineral and/or surface rights as a complex collection of owned and/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 24,092 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 3,509 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 total book value of the PAMC and its associated plant and equipment as of December 31, 2024 is approximately $1.4 billion.

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 annual production capacity of the PAMC is up to 28.5 million tons of coal. 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. As of December 31, 2024, the Company held more than $380 million in surety bonds to cover its obligations relating to mining and reclamation, mine subsidence, road repairs, stream restoration, water loss and dam safety with respect to the PAMC.

Bailey Mine. As of December 31, 2024, the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 125.9 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 3.76. The Bailey Mine is the first mine developed at the Pennsylvania Mining Complex. 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, 2024, 2023 and 2022, the Bailey Mine produced 10.8, 11.2 and 11.6 million tons of coal, respectively.

Enlow Fork Mine. As of December 31, 2024, the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 239.2 million tons of clean recoverable coal with an average as-received gross heat content of approximately 13,011 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.06. The Enlow Fork Mine is located directly north of the Bailey Mine. Initial underground development was 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, 2024, 2023 and 2022, the Enlow Fork Mine produced 9.2, 8.7 and 6.3 million tons of coal, respectively.

Harvey Mine. As of December 31, 2024, the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 192.5 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,940 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 4.08. The Harvey Mine is located directly east 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, 2024, 2023 and 2022, the Harvey Mine produced 5.7, 6.2 and 6.1 million tons of coal, respectively.

The following table sets forth additional information regarding the recoverable coal reserves at the Pennsylvania Mining Complex.

PENNSYLVANIA MINING COMPLEX - MATERIAL RESERVES

Recoverable Coal Reserves as of December 31, 2024 and 2023

Itmann Mining Complex - Non-Material Reserves

Itmann No. 5 Mine. The Itmann No. 5 Mine is located in Wyoming County, West Virginia, approximately 2.5 miles northwest of the town of Itmann at approximately 37°35’23.65” N latitude and 81°27’14.43” W longitude. The Company controls approximately 20,224 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 (95%) 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, 2024, the Itmann No. 5 Mine's assigned and accessible reserve base contained an aggregate of 27.5 million tons of clean recoverable coal, enough to allow for more than 30 years of full-capacity production. These reserves contain an approximate average quality on a dry basis of 0.98% sulfur, 7.2% ash, and 19.3% volatile matter. Coal from the Itmann No. 5 Mine is currently extracted by underground methods using 6 continuous miner units in 3 super sections to achieve expected future capacity of approximately 900 thousand clean tons per year. For the years ended December 31, 2024, 2023 and 2022, the Itmann No. 5 Mine produced 393 thousand, 316 thousand and 164 thousand tons of coal, respectively.

General access to the Itmann No. 5 Mine is via a well-developed network of primary and secondary roads serviced by state and local governments. These roads offer direct access to the mine and processing facilities and are typically open year-round. Primary vehicular access to the property is via State Route 10/16, which follows the north bank of the Guyandotte River. The Guyandotte Class I rail line runs along the south bank of the Guyandotte River. Sources of electrical power, water, supplies and materials are readily available. Electrical power is provided to the mines and facilities by a regional utility company. Water is recycled from the abandoned underground Itmann No. 1 and No. 2 Mines or supplied by water wells.

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 TPH 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 TPH of product along with a 3,500 TPH 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.

As of December 31, 2024, the Company held less than $1 million in surety bonds to cover its current obligations relating to mining and reclamation, mine subsidence, stream restoration and water loss with respect to the Itmann No. 5 Mine, preparation plant facility and refuse area.

The following table sets forth additional information regarding the recoverable coal reserves at the Itmann Mining Complex.

ITMANN MINING COMPLEX - NON-MATERIAL RESERVES

Recoverable Coal Reserves as of December 31, 2024 and 2023

Other Properties - Non-Material Reserves and Resources as of December 31, 2024

The Company also holds other greenfield recoverable coal reserves and coal resources located in NAPP, CAPP and ILB, which are not deemed individually material and had an estimated 1,341.8 million tons of recoverable coal reserves and coal resources. The Company’s estimate includes recoverable high-vol, mid-vol or low-vol metallurgical coal reserves and resources of 99.9 million tons and 112.5 million tons, respectively. Additionally, worldwide demand for metallurgical coal allows some of our recoverable coal reserves and 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, 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 non-operating recoverable coal reserves and coal resources by region.

Non-Material, Non-Operating Recoverable Coal Reserves and Coal Resources

as of December 31, 2024 and 2023

Title to coal properties that we lease or purchase and the boundaries of these properties 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 reserves are discovered in the future, control of and the right to mine reserves 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, 2024, 2023 and 2022.

• Excludes advanced mining royalty payments received of $746, $529 and $381 during the years ended December 31, 2024, 2023 and 2022, 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.

Production as of December 31, 2024

In the year ended December 31, 2024, 98.5% of the Company's production came from underground mines equipped with longwall mining systems. The Company employs longwall mining techniques in its underground mines where the geology is favorable and reserves are sufficient, namely, in the three mines located at the PAMC. Underground longwall mining uses continuous mining units to develop the mains and gate roads for longwall panels. The longwall systems are highly mechanized, capital-intensive operations to efficiently extract coal within the longwall panels. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because the Company has substantial reserves readily suitable to these operations, the Company believes that these longwall mines can increase production volumes at a low incremental cost.

The following table shows the production, in millions of tons, for the Company's mines for the years ended December 31, 2024, 2023 and 2022, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquired by us.

Table may not sum due to rounding.

Coal Marketing and Sales as of December 31, 2024

The following table sets forth tons sold and average coal revenue per ton sold for the periods indicated:

We sell coal produced by our mines and additional coal that is purchased by us from other producers. Approximately 36% of our 2024 coal revenue was from U.S. electric generators, 60% of our 2024 coal revenue was from export markets and 4% of our 2024 coal revenue was from other domestic customers. Approximately 32% of our 2023 coal revenue was from U.S. electric generators, 66% of our 2023 coal revenue was from export markets and 2% of our 2023 coal revenue was from other domestic customers. Approximately 45% of our 2022 coal revenue was from U.S. electric generators, 53% of our 2022 coal revenue was from export markets and 2% of our 2022 coal revenue was from other domestic customers.

We had sales to approximately 50 customers from our coal operations during the past two years. During 2024, two customers each comprised over 10% of our total sales, aggregating approximately 22% of our total sales. During 2023, two customers each comprised over 10% of our total sales, aggregating approximately 23% 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 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. Additionally, in 2024, Arch sold coal to domestic customers located in 25 different states as the location of its mines enabled it to ship coal to most of the major coal-fueled power plants in the United States and exported coal to Europe, Asia, Central and South America, and Africa.

Coal Contracts and Pricing

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

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

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

Of our 2024 sales tons, approximately 57% were sold to export markets and 43% were sold to domestic customers. Of our 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.

During the past two years, on coal revenue of $1.7 billion in 2024 and $2.0 billion in 2023, our average coal revenue per ton sold for coal produced from the PAMC was $65.54/ton in 2024 and $77.74/ton in 2023. Pricing for our product depends strongly on conditions in the domestic and international thermal and metallurgical coal markets.

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 Northern Appalachian coal, (ii) prices for other competing sources of energy used for electricity generation, such as natural gas, (iii) power prices in the regions we serve, (iv) prices for coals from other basins (including CAPP, ILB and PRB) 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 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 electricity generation, such as natural gas, (v) prices for other export coals that compete in these same markets, and (vi) pricing under our longer-term contracts, which may have been entered into under different market conditions.

Distribution

Coal is transported from the Company’s mining operations to customers predominantly by railroad cars, vessels or a combination of these means of transportation. Most customers negotiate their own transportation rates, while 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 for the remaining customers.

Seasonality

Our business has historically experienced limited variability in its results due to the effect of seasonal changes. Demand for coal-fired 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 coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to transport coal over our overland conveyor systems and to transport our coal by rail.

Competition

The coal industry is highly competitive, with numerous producers selling into all markets that use coal. There are numerous large and small producers in all coal-producing basins of the United States, 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 United States. 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 generation industry. These coal consumption patterns are influenced by many factors that are beyond our control, including 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 from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly older, less efficient coal-fired powered 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.

Human Capital Management

As of December 31, 2024, we had 2,076 employees, of which 41 CONSOL Marine Terminal employees were represented by a collective bargaining agreement. Following the Merger, which closed on January 14, 2025, we had 5,389 employees, of which 41 CONSOL 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 38% of the Company's workforce with at least 10 years of company service coupled with our average voluntary retention rate of 89% as of the end of fiscal year 2024 reflects the engagement of our employees.

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

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

Laws and Regulations

Overview

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

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

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. In recent years, these Executive Orders and other Presidential Directives have been subject to revision, repeal and judicial challenge with uncertain outcomes. For example, former President Joe Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and to suspend, revise or rescind prior agency actions that the administration identified as conflicting with its policies. Upon taking office, President Trump rescinded several Executive Orders that were key to former President Biden’s environmental agenda, creating additional regulatory uncertainty.

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 and financial condition, and/or demand for our coal product by our customers.

Environmental Laws

Clean Air Act. The 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, modification or expansion of certain facilities. Indirectly, the CAA affects the U.S. coal industry by extensively regulating the air emissions of coal-fired electric power generating 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, 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 electric generating 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 electric generating plants will be decommissioned or replaced with alternative sources of fuel and reduce the likelihood that new coal-fired plants will be built in the future.

On January 20, 2025, President Trump issued an Executive Order titled “Unleashing American Energy.” Among other things, that order directs all federal agency heads to “review all existing regulations, orders, guidance documents, policies, settlements, consent orders, and any other agency actions” to identify any agency actions that are inconsistent with the administration’s energy and environmental policies or that “impose an undue burden on the identification, development, or use of domestic energy resources. The order further requires the EPA Administrator to submit a recommendation to the White House Office of Management and Budget regarding the legality and continuing applicability” of the EPA Administrator’s Endangerment and Significant Contribution Finding for greenhouse gases, which was made under Section 202(a) of the CAA in December 2009. Actions to give effect to this Executive Order could have significant effects on the EPA’s CAA regulatory programs, although the nature of those effects is, at this time, unclear.

Mercury and Air Toxics Standards Rule. In 2012, the United States Environmental Protection Agency (“EPA”) promulgated a rule for National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for new and existing coal-fueled and oil-fueled electric generating plants. The EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) imposed MACT emissions limitations on Hazardous Air Pollutants (“HAPs”), such as mercury, acid gas HAPs, HAP metals and organic HAPs, for applicable facilities. The rule was challenged, and ultimately found arbitrary and capricious by the U.S. Supreme Court in 2015, for failing to consider the costs imposed by the MATS Rule. The D.C. Circuit remanded the rule without vacating it. In 2020, the EPA finalized the MATS Reconsideration Rule, reversing the agency's “appropriate and necessary” conclusion even while retaining coal- and oil-fired power plants on the list of affected source categories and maintaining existing emission limits for mercury and other HAPs. The final rule was subject to legal challenge in multiple cases before the D.C. Circuit. In February 2022, the EPA published its proposed rule revoking the 2020 MATS Reconsideration Rule and reaffirming the “appropriate and necessary” supplemental finding, with a final rule published in 2023. In a related May 2024 rulemaking, the EPA published the Residual Risk and Technology Review (“RTR”) rule, finalizing amendments to the NESHAPs for coal- and oil-fired electric utility steam generating units. In August 2024, a request to stay the rule pending judicial review was denied by the D.C. Circuit. Subsequently, emergency applications to stay the rule were denied by the Supreme Court in October 2024 while litigation is ongoing. The emissions limitations in the final rule, or similar future rulemakings, could require our customers to incur significant capital costs associated with installation of emissions control technologies, which could negatively affect the demand and prices for our coal, our business and results of operations.

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 (“SO 2”), 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. In 2020, the EPA finalized decisions to retain the 2015 NAAQS for ozone and PM; however, both decisions were subject to legal challenge. Related to the ozone NAAQS, in August 2023, the EPA announced that it would not complete its reconsideration of the 2020 decision to retain the NAAQS but would instead begin a new review of the ozone NAAQS, which is ongoing. Related to the PM NAAQS, the EPA published a final rule lowering the standard for fine particulate matter (“PM 2.5”) which became effective in May 2024, but is subject to ongoing litigation in the D.C. Circuit Court of Appeals. Separately, in December 2024, the EPA completed its review of the secondary public welfare NAAQS for NOx, SO 2 and PM, electing to retain the existing standards for NOx and PM and to lower the standard for SO 2 with an effective date of January 27, 2025. This final rule is also the subject of a judicial challenge. New NAAQS review proceedings for NOx and ozone have been announced and are in preliminary phases. New and recent revisions to the NAAQS could trigger new nonattainment areas that would result in more stringent SIPs that require significant investment in emissions control technologies associated with our or our customers' operations, and could adversely affect our costs and the demand for our coal.

Good Neighbor Plan. In February 2023, the EPA issued its Final Disapproval of SIPs submitted by 21 states pursuant to the “good neighbor” provisions of the CAA 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 the majority of cases. The U.S. Court of Appeals for the Sixth Circuit has, however, ruled in December 2024 that the EPA’s disapproval of Kentucky’s SIP was unlawful.

Following these SIP disapprovals, in March 2023, the EPA published the final Good Neighbor Plan for the 2015 Ozone NAAQS, which applies to power plants and industrial facilities in 23 states. The rule relies, in part, on a NOx allowance trading program for electricity generating units (“EGUs”), and requires operation of existing, and installation of new, emissions control technologies for EGUs and other industrial sources. In June and September 2023, the EPA issued two interim final rules amending the Good Neighbor Plan to administratively stay the effectiveness of the rule in 12 of the 23 states, in response to judicial orders partially staying the EPA's disapproval of the SIPs.

In addition to the challenges to the SIP disapprovals, parties also challenged the EPA’s Good Neighbor Plan itself in the D.C. Circuit. In June 2024, while the D.C. Circuit proceedings were ongoing, the Supreme Court issued a decision temporarily blocking implementation of the Good Neighbor Plan while litigation is ongoing. To comply with the Supreme Court's order, in October 2024, the EPA issued a third interim final rule temporarily amending the Good Neighbor Plan to administratively stay requirements for covered facilities in the remaining 11 states for which an administrative stay was not previously implemented, including Maryland and Pennsylvania. The three interim final rules include provisions to ensure covered facilities continue to mitigate emissions with respect to the 2008 ozone NAAQS while the Good Neighbor Plan is stayed. The stay will remain in effect pending the litigation challenging the Good Neighbor Plan before the D.C. Circuit and any related proceedings in the U.S. Supreme Court. As a result of these related rulemakings and depending on the outcome of these various legal proceedings, we and our customers could incur significant compliance costs that may lead to accelerated EGU closures or fuel switching, which could adversely affect the demand for our coal.

Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units under CAA Section 111(d). In October 2015, the EPA published a final rule under section 111(d) of the CAA known as the Clean Power Plan (“CPP”), which required states to create systems that reduce carbon dioxide (“CO 2”) emissions from existing fossil fuel-fired EGUs by 28% in 2025 and 32% in 2030, compared to 2005 levels. The CPP was subject to numerous legal challenges and was stayed by the U.S. Supreme Court, pending the D.C. Circuit's review of the rule. The D.C. Circuit never reviewed the CPP because the EPA decided to reconsider it.

Following its reconsideration of the CPP, in July 2019, the EPA published the Affordable Clean Energy (“ACE”) rule which repealed the CPP and established greenhouse gas (“GHG”) guidelines for states to use when developing plans to limit CO 2 emissions from coal-fired EGUs. The ACE rule provided that heat rate efficiency improvements are the Best System of Emission Reduction (“BSER”) for coal-fired electric utility sources under the CAA, directed states to develop specific SIPs to implement the rule, and revised CAA section 111(d) regulations to give states greater authority regarding these plans. Several states and public interest groups filed petitions seeking review and reconsideration of the ACE rule. In March 2021, the D.C. Circuit issued its partial mandate vacating the ACE rule but leaving the CPP Repeal intact to allow time for the EPA to issue a new rule under section 111(d). Separately, the Supreme Court agreed to hear four consolidated legal appeals to the D.C. Circuit decision striking down the ACE rule. In June 2022, the Supreme Court issued its decision reversing the D.C. Circuit's ruling and limiting expansive interpretations of the EPA's authority under Section 111 of the CAA, while generally upholding the EPA's authority to regulate GHGs as air pollutants and remanding the case for further proceedings.

On May 9, 2024, the EPA published a suite of final rulemakings repealing the ACE Rule and promulgating GHG emission guidelines for existing fossil fuel-fired EGUs, with an effective date of July 8, 2024. For existing coal-fired EGUs, the rules establish the BSER based on the EGU retirement date. For EGUs in operation on or after January 1, 2039, the rule requires EGUs to be equipped with Carbon Capture and Storage (“CCS”) with 90 percent capture on or before January 1, 2032. For EGUs that will cease operations by January 1, 2039, the rule requires compliance with a numeric emission rate based on 40 percent co-firing natural gas with coal on or before January 1, 2030. Coal-fired EGUs planning to permanently cease operations before January 1, 2032 will not be subject to emissions guidelines. This suite of rules was challenged in ongoing litigation before the D.C. Circuit.

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. In July 2024, a request to stay the rule pending judicial review was denied by the D.C. Circuit Court of Appeals. Subsequently, in October 2024, the Supreme Court denied emergency applications to stay the rule while litigation is ongoing. Such actions make alternative sources of energy more competitive and could negatively affect the demand and prices for our coal, thereby having a material adverse impact on our business and results of operations.

New Source Performance Standards (“NSPS”) for Greenhouse Gas Emissions from New, Modified, or Reconstructed Fossil Fuel-Fired EGUs Under CAA Section 111(b). In October 2015, the EPA published a final rule limiting CO 2 emissions from new, modified and reconstructed fossil fuel-fired EGUs under section 111(b) of the CAA and identifying partial CCS as BSER. The rule was subject to numerous legal challenges in the D.C. Circuit that continue to be held in abeyance pending the EPA's review of the rule. In December 2018, the EPA published a proposed rule proposing to change its BSER determination from partial CCS to use of a supercritical boiler but the EPA never took final action on that proposal. In January 2021, the EPA finalized its “Pollutant Specific Significant Contribution Finding (“SCF”) for Greenhouse Gas Emissions from New, Modified and Reconstructed Electric Utility Generating Units” rule, concluding that the EGU source category GHG emissions are significant and warrant regulation. Although the SCF rule was subsequently challenged in court, the case was ultimately vacated because Congress revoked the rule through the Congressional Review Act in June 2021. On May 23, 2023, the EPA published a notice of proposed rulemaking (“NPRM”) proposing to retain the NSPS for coal-fired EGUs that was promulgated in 2015 and was based on partial CCS. While no new coal-fired power stations are currently under construction in the U.S., promulgation of rules limiting CO 2 emissions or requiring deployment of advanced technologies such as CCS will promote continuation of this trend. A lack of investment in construction, modification or reconstruction of coal-fired EGUs could negatively affect the demand and prices for our coal, thereby having a material adverse impact on our business and results of operations.

Global Climate Change

Our customers' consumption of the coal we produce results in the emission of GHGs, particularly CO 2. During operations, our coal mines release methane, a GHG, to promote a safe working environment for our miners underground. GHGs are believed to contribute to warming of the earth’s atmosphere and other climatic changes. As a result, global climate change initiatives, including imposition of taxes or fees and promulgation of regulations intended 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. Additionally, regulations intended to limit or reduce emissions of methane from coal mines (discussed below) could have a direct impact on our results of operations.

To date in the U.S., no legislation to comprehensively regulate global climate issues and GHG emissions has been signed into law. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements are uncertain. In the United States, findings published by the EPA in 2009 concluded that GHG emissions pose an endangerment to public health and the environment, and as a result, the EPA has the authority to adopt and implement regulations restricting GHG emissions under existing provisions of the CAA.

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”). These emissions are not currently regulated by the EPA. Previous petitions and judicial challenges seeking to compel the EPA to classify coal mines as stationary sources appropriate for regulation have been unsuccessful to date. If the EPA were to regulate coal mine methane emissions in the future, we may 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 final regulation and the degree of emission reduction prescribed.

In federal, state and international jurisdictions, 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 have been proposed or enacted. 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. An administrative stay of the rule was subsequently granted by the Fifth Circuit Court of Appeals, pending ongoing judicial review. Similar rules, such as the California Climate Corporate Data Accountability Act and the EU Corporate Sustainability Reporting Directive impose similar reporting obligations in future years. 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. In addition to challenges related to compliance burden, climate disclosure rules could proliferate investment bias and practices by investors and financial institutions to exclude our securities from investment portfolios or increase our cost of capital, regardless of the Company's results, strategy or financial performance.

In the absence of sweeping federal legislation on GHG emissions in the United States, 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, to accelerate closure of existing coal-fired power generating stations, 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.

At the state level, in response to a 2019 Executive Order by Governor Tom Wolf, Pennsylvania adopted a regulation that would allow Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”) in 2022. RGGI is a mandatory cap-and-trade program among 10 northeastern states to reduce CO 2 emissions from the power sector. Similar to other mandatory cap-and-trade initiatives, such as California's cap-and-trade program, RGGI seeks to limit CO 2 emissions annually, in order to achieve a prescribed long-term emissions reduction target. In cap-and-trade scenarios, 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 CO 2 emissions, thereby increasing the cost of electric power generation and incentivizing the power generator to limit their CO 2 emissions by combusting fewer fossil fuels, including coal.

Pennsylvania's RGGI regulation was subject to immediate legal challenge, and in 2023, the Pennsylvania Commonwealth Court issued its decision striking down Pennsylvania's participation in RGGI and determining that RGGI constitutes an illegal tax under the Pennsylvania Constitution. The decision was appealed to the Supreme Court of Pennsylvania, and a ruling is expected in 2025. Separately, in May 2024, the Pennsylvania Climate Emissions Reduction (“PACER”) Program was introduced in the Pennsylvania legislature. PACER proposes to establish a Pennsylvania-specific cap and invest program setting a cap on GHG emissions from Pennsylvania's fossil fuel-fired power plants. If enacted, either the RGGI regulation or the PACER legislation could result in decreased demand or decreased prices for our coal in the Commonwealth of Pennsylvania. Additional CO 2 cap-and-trade programs, carbon taxes, or other regulatory and policy regimes, whether state, federal or international in nature, or similar business or customer-focused voluntary climate and GHG emission reduction goals could affect the future market for coal and lower overall coal demand.

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 the states of California, Massachusetts and Maryland. Modeled after the Comprehensive Environmental Response, Compensation and Liability (“CERCLA”) Superfund law, 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 state and federal 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, the uncertainty surrounding the economic viability of these projects under future laws limiting CO 2 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 binding 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. In December 2023, the UNFCCC convened its 28th COP and ratified the UAE Consensus which calls upon its signatories, including the United States, to achieve a 43% reduction in GHG emissions by 2030 (compared to 2019 levels) through actions such as the accelerated phase-down of unabated coal power and other measures that drive the transition away from fossil fuels in energy systems. As a result, 12 nations revised and submitted economy-wide nationally determined contributions (“NDCs”) by February 10, 2025, including plans to accelerate targets aligned with the Paris Agreement's temperature goals. The majority of countries are due to publish their NDCs throughout the year ahead of the 30th COP set for November 2025. On January 20, 2025, President Donald J. Trump issued an executive order directing that the United States formally withdraw from the Paris Agreement.

Federal, state and international GHG and climate change initiatives, associated regulations or other voluntary commitments to reduce GHG emissions could significantly increase the cost of coal production and consumption, increase costs as a result of regulations requiring the installation of emissions control technologies, increase expenses associated with the purchase of emissions reduction credits to comply with future emissions trading programs, increase expenses associated with any future carbon tax, or significantly reduce coal consumption through implementation of a future clean energy standard. Such initiatives and regulations could further reduce demand or prices for our coal in both domestic and international markets, could adversely affect our ability to produce coal and to develop our reserves, could reduce the value of our coal and coal reserves, and may have a material adverse effect on our business, financial condition and results of operations.

Clean Water Act

The federal Clean Water Act (“CWA”) and corresponding state laws affect our coal and export terminal operations by regulating discharges into certain waters. 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 for non-traditional pollutants, such as chlorides, sulfates, selenium and dissolved solids and (ii) mandates to dispose of wastes at approved disposal facilities.

Under the CWA, citizens may sue permit holders for alleged discharges of regulated pollutants not explicitly limited by permits issued pursuant to the National Pollutant Discharge Elimination System (“NPDES”). Citizens may also sue to enforce NPDES permit requirements. Since 2012, multiple citizen suits have been filed against various coal operators, alleging violations of numeric and narrative water quality standards that broadly prohibit effects to aquatic life. While the outcome of these suits cannot be predicted, the suits seek penalties and injunctive relief that could limit future discharges or require installation of capital-intensive water treatment technologies that have high operating costs. 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 United States, 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 2020, the EPA issued the 2020 CWA Section 401 Certification Rule, intending to clarify the scope of state regulatory authority and, under certain circumstances, allowing the EPA to certify projects regardless of state objection. The rule was vacated by the U.S. District Court for the Northern District of California in October 2021. In June 2022, the EPA published a proposed revised section 401 certification rule expanding the role of states, territories and Tribes in the certification process. The final 2023 CWA Section 401 Water Quality Certification Improvement Rule became effective on November 27, 2023 but has been challenged by states and regulated entities to enjoin its enforcement in a lawsuit pending in the U.S. District Court for the Western District of Louisiana. On March 7, 2024, the District Court in that case denied a limited motion for preliminary injunction to enjoin enforcement of the 2023 Rule for those Section 401 certification requests submitted after the effective date of the 2020 Rule, but before the effective date of the 2023 Rule. The District Court has yet to rule on the merits of petitioners’ challenge to the 2023 Rule and it remains in effect. While the 2023 Rule is in effect, we may be required to receive explicit authorization from the ACOE and the corresponding state regulatory authority before proceeding with certain mining or export terminal activities. As a result, our operations could experience permitting delays or disapprovals or could be subject to litigation, which could have a material adverse effect on our business, results of operations, financial condition and cash flows. Due to the ongoing litigation and possibility that the EPA may revise the 2023 Rule in the future, the ultimate impact of the 2023 Rule cannot be determined at this time.

Definition of Waters of the United States. In June 2015, the EPA issued a rule to clarify which waterways are subject to federal jurisdiction under the CWA, known as the Clean Water Rule. The rule was ultimately blocked by a federal appeals court, and, in 2020, the EPA and the ACOE published the Navigable Waters Protection Rule (“NWPR”) to revise the definition of “Waters of the United States” (“WOTUS”) and to redefine which waterbodies are subject to federal jurisdiction. The NWPR was vacated by multiple U.S. District Courts, and, in January 2023, the EPA and the ACOE issued a final rule redefining WOTUS in a manner generally consistent with the pre-2015 framework (“Revised WOTUS Rule”). On May 25, 2023, the Supreme Court issued its decision in Sackett v. EPA, which narrowed federal jurisdiction over land and water features. When the Sackett decision was issued, two federal district courts had already enjoined the Revised WOTUS Rule in several states. On August 29, 2023, the EPA and the ACOE issued a final rule to amend the 2023 Revised WOTUS Rule and conform the rule with the Sackett decision (the “Conforming Rule”). The Conforming Rule took effect immediately upon publication on September 8, 2023. However, as a result of ongoing litigation on the Revised WOTUS Rule, the agencies are implementing the definition of “waters of the United States” under the Revised WOTUS Rule, as amended by the Conforming Rule, in 24 states, the District of Columbia and the U.S. Territories. In the other 26 states, the agencies are interpreting “waters of the United States” consistent with the pre-2015 regulatory regime and the Sackett decision until further notice. Notably, the Conforming Rule itself does not define certain language from the Supreme Court's ruling and could be expanded or face additional legal challenges in the future. Further revisions to the definition of WOTUS could impose additional or different permitting obligations or restrictions, require enhanced mitigation, or cause the Company to modify its operations, any of which could result in delayed permit approval timeframes or increased operational costs and compliance burden.

Water Discharge Permits. Additionally, the Company must obtain NPDES permits from the appropriate state or federal 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.

On September 26, 2023, the Sierra Club and several other environmental organizations filed a “Petition for Rulemaking to Establish a Nationwide NPDES Permit for Uncovered Railcars Transporting Coal Pursuant to 33 U.S.C. § 1342(a).” If the Petition results in final rulemaking, it could impose permitting obligations or restrictions on our rail partners and could impact the time and costs associated with the transportation of our coal. No action was taken by the EPA on the petition prior to the Biden administration leaving office.

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. Portions of the rule were vacated by the U.S. Court of Appeals for the Fifth Circuit in 2019. Accordingly, 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. The rule is expected to significantly increase compliance costs for many coal-fired power plants and as a result, could accelerate facility closures. Certain domestic utilities, including some of our current customers, have announced plans to retire certain coal-fired power plants by 2028 as a result of the ELG rule. In May 2024, the EPA published the final Supplemental ELG Rule, which further restricts the ELGs established by the 2020 ELG Reconsideration Rule, incorporates limitations for additional waste streams that were previously excluded and establishes procedural requirements for affected facilities to demonstrate permanent cessation of coal combustion or permanent retirement.

Multiple states, trade groups and utility companies challenged the EPA’s May 2024 Supplemental ELG Rule. On October 9, 2024, the Eighth Circuit Court of Appeals denied the petitioners’ request to stay the Supplemental ELG Rule, thereby allowing the rule to go into effect while the litigation is ongoing. The decision was appealed to the Supreme Court, where it is pending while the underlying legal challenge on the merits of the rule continues. The ultimate impact of the Supplemental ELG Rule cannot be determined at this time due to uncertainty over the outcome of legal challenges. There is also the possibility that the EPA under a new administration will seek to revise or modify the rule, which would also likely face legal challenges. The legal challenge to the Supplemental ELG Rule or further revisions could impose additional or different permitting obligations or restrictions, or cause the Company to modify its operations, any of which could result in delayed permit approval timeframes or increased operational costs and compliance burden.

Other Environmental Laws and Regulations

Surface Mining Control and Reclamation Act. The 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 Clean Air Act, Clean Water Act, Endangered Species Act and other statutes discussed herein. Operators must obtain SMCRA permits and permit renewals from the U.S. Office of Surface Mining (“OSM”) or from the applicable state agency, where states have been granted regulatory primacy by demonstrating that the state’s regulatory program is at least as stringent as the federal program. Our active operations are located in states that have primary jurisdiction for enforcement of SMCRA, with oversight from OSM. 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 state, federal 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 therefor. Over the past few years, the 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 unfavorable, including increases in the amount of collateral required to secure surety bonds. However, more recently, we have seen insurance rates 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 state and federal 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, 2024, we posted an aggregated $526 million in surety bonds for reclamation purposes, as well as approximately $137 million in surety bonds, cash, 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 (“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 $74.2 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 2024, the Company has contributed $12.1 million to the fund, and the PADEP has approved bond reductions totaling $52.7 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 fee is $0.096 per ton for underground mined coal and became effective in October 2021. We recognized expense related to Abandoned Mine Reclamation Fund fees of $2 million for the year ended December 31, 2024.

Endangered Species Act. The federal Endangered Species Act (“ESA”) and other related federal and state statutes protect species that have been classified as endangered or 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 to rescind and revise the regulations and definitions finalized under the previous administration, related to procedures for listing threatened and endangered species and agency consultation. 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.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions, prior to taking a “major Federal action,” which encompasses agencies' decisions on certain permitting applications that fall under federal jurisdiction. Agencies generally must issue either an Environmental Impact Statement (“EIS”) or an Environmental Assessment (“EA”), including an evaluation of direct and indirect impacts associated with GHG emissions and the effects of climate change compared to reasonable alternatives, including a no action alternative. The White House Council on Environmental Quality (“CEQ”) has been responsible for issuing regulations that generally govern the implementation of NEPA, although individual agencies can issue their own rules. On November 12, 2024, the D.C. Circuit issued a decision in Marin Audubon Society et al. v. FAA et al., holding that CEQ lacked statutory authority to issue NEPA rules. The ultimate effect of this ruling on the future implementation of NEPA and the burdens the law will impose are, at this time, unclear. When applicable to federal permit applications required for mining, NEPA reviews may create delays in authorization timeframes, increase the cost of compliance, risk denial of a permit application or give rise to litigation risk, which could materially impact our operations.

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, 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 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 created throughout the coal mining process. 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.

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 (the “2015 CCR Rule”) and classified CCR as “non-hazardous” waste. The CCR Rule was subject to legal challenge and in 2018, the D.C. Circuit remanded the rule at the EPA's request. In August 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closures between 2021 and 2028, depending on site-specific circumstances. Provisions exempting inactive impoundments at inactive facilities from the CCR Rule were vacated by the D.C. Circuit in 2018, and the EPA proposed additional rules addressing those specific provisions in May 2023. In 2022 and 2023, the EPA denied requests from the majority of CCR facilities that sought approval to continue disposal of CCR and non-CCR waste streams, and instead required the facilities to cease receipt of waste within 135 days of completion of public comment. Future determinations of the same nature, or similar actions in expected future rulemakings, could lead to accelerated, abrupt, or unplanned suspension of coal-fueled EGUs. The CCR rules impose new requirements that would generally increase the cost of CCR management or require facility closure. The combined effect of the CCR rules and ELG regulations (discussed above) has compelled power-generating companies to close existing ash ponds and may force the closure of certain existing coal-burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

Other Environmental Regulations. We are required to comply with other state, federal 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.

Health and Safety Laws

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

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

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

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

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

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

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

•more stringent rock dusting requirements; and

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

In September 2015, 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.

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 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. In January 2022, these rates expired and reverted back to pre-2008 levels, at $0.50 per ton for deep mined coal and $0.25 per ton for surface-mined coal, neither amount to exceed 2.0% of the gross sales price. However, the Inflation Reduction Act of 2022 made the higher rates (of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal) permanent, effective in October 2022. The Company recognized expense related to the Black Lung Excise Tax of $11.0 million, $10.9 million and $8.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.

In December 2021, the 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 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 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 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 are required to remit the increased security amount within one year. The final rule, including any assessments, is subject to appeal.

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.

Other State and Local Laws Related to Our Coal Business

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

Available Information

We maintain a website atwww.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 at the SEC’s website, www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.