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(Exact name of registrant as specified in its charter)

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 x Yes   ¨ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 ¨ Yes   x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

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

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

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

The aggregate market value of the Common Stock held by non-affiliates of the registrant (excluding outstanding shares beneficially owned by directors, executive officers, and other affiliates) on June 30, 2025, was approximately $761.0 million based on the closing price of the Company’s common stock as reported that date on the New York Stock Exchange of $112.48 per share. Such assumptions should not be deemed to be conclusive for any other purpose. 

Number of shares of the registrant’s Common Stock, $0.01 par value per share, outstanding as of February 20, 2026: 12,792,685

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2026 annual meeting of stockholders (the “Proxy Statement”), which will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2025.

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements.” These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “predict,” “project,” “should” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements, but these terms and phrases are not the exclusive means of identifying such statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those expressed in or implied by these forward-looking statements.

The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•depressed levels or declines in coal prices;

•the financial performance of the company;

•our liquidity, results of operations and financial condition;

•our ability to generate sufficient cash or obtain financing to fund our business operations;

•worldwide market demand for coal and steel, including demand for U.S. coal exports, and competition in coal markets;

•railroad, barge, truck, port and other transportation availability, performance and costs;

•steel and coke producers switching to alternative energy sources such as natural gas, renewables and coal from basins where we do not operate;

•our ability to meet collateral requirements for, and fund, employee benefit obligations;

•our ability to self-insure certain of our black lung obligations;

•our ability to obtain or renew surety bonds on acceptable terms or maintain our current bonding status;

•the imposition, continuation or modification of barriers to trade, such as tariffs, and the unpredictability of these events;

•attracting and retaining key personnel and other employee workforce factors, such as labor relations;

•our ability to consummate financing or refinancing transactions, and other services, and the form and degree of these services available to us, which may be significantly limited by the lending, investment and similar policies of financial institutions and insurance companies regarding carbon energy producers, the environmental impacts of coal combustion or other factors;

•our costs of complying with health and safety regulations, including but not limited to MSHA’s silica regulations;

•changes in domestic or international environmental laws and regulations, and court decisions, including those directly affecting our coal mining and production and those affecting our customers’ coal usage, including potential climate change initiatives;

•failures in performance, or non-performance, of services by third-party contractors, including contract mining and reclamation contractors or other counterparties;

•disruptions in delivery or changes in pricing from third-party vendors of key equipment and materials that are necessary for our operations, such as diesel fuel, steel products, explosives, tires and purchased coal;

•our production capabilities and costs;

•inflationary pressures on supplies and labor and significant or rapid increases in commodity prices;

•our indebtedness as we may incur it from time to time;

•our ability to execute our share repurchase program;

•cybersecurity attacks or failures, threats to physical security, extreme weather conditions or other natural disasters;

•increased volatility and uncertainty regarding worldwide markets, seaborne transportation and our customers as a result of developments in and around Ukraine, Venezuela and the Middle East;

•changes in, renewal or acquisition of, terms of and performance of customers under coal supply arrangements and the refusal by our customers to receive coal under agreed-upon contract terms;

•reductions or increases in customer coal inventories and the timing of those changes;

•our ability to obtain, maintain or renew any necessary permits or rights;

•inherent risks of coal mining, including those that are beyond our control;

•changes in, interpretations of, or implementations of domestic or international tax or other laws and regulations, including the Inflation Reduction Act of 2022 and its related regulations;

•our relationships with, and other conditions affecting, our customers, including the inability to collect payments from our customers if their creditworthiness declines;

•reclamation and mine closure obligations;

•our assumptions concerning economically recoverable coal reserve estimates; and

•other factors, including the other factors discussed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections included elsewhere in this Annual Report on Form 10-K.

The list of factors identified above is not exhaustive. We caution readers not to place undue reliance on any forward looking statements, which are based on information currently available to us and speak only as of the dates on which they are made. When considering these forward-looking statements, you should keep in mind the cautionary statements in this report. We do not undertake any responsibility to publicly revise these forward-looking statements to take into account events or circumstances that occur after the date of this report. Additionally, except as expressly required by federal securities laws, we do not undertake any responsibility to update you on the occurrence of any unanticipated events, which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this report.

Acquisition. Refers to the transaction by which the Company acquired certain of Alpha Natural Resources Inc.’s core coal operations as part of the Alpha Natural Resources, Inc. Restructuring.

Alpha. Alpha Metallurgical Resources, Inc. (the “Company”) (previously named Contura Energy, Inc.).

Alpha Natural Resources, Inc. Restructuring. On August 3, 2015, Alpha Natural Resources, Inc. and each of its wholly owned domestic subsidiaries other than ANR Second Receivables Funding LLC (collectively, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “VA Bankruptcy Court”). The VA Bankruptcy Court approved the Debtors’ Plan of Reorganization on July 7, 2016. On July 26, 2016, a consortium of former creditors of the Debtors acquired the Company’s common stock in exchange for a partial release of their creditor claims pursuant to the Debtors’ bankruptcy settlement. The Debtors, collectively, were a coal producer with operations in Central Appalachia, Northern Appalachia, and the Powder River Basin.

Ash. Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Bituminous coal. Coal used primarily to generate electricity and to make coke for the steel industry with a heat value ranging between 10,500 and 15,500 BTUs per pound.

British Thermal Unit or BTU. A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Central Appalachia or CAPP. Coal producing area in eastern Kentucky, Virginia, southern West Virginia and a portion of eastern Tennessee.

Coal reserves. The economically mineable part of a measured or indicated coal resource, which includes diluting materials and allowances for losses that may occur when coal is mined or extracted.

Coal resources. Coal deposits in such form, quality, and quantity that there are reasonable prospects for economic extraction.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

Coking coal. Coal used to produce coke, the primary source of carbon used in steelmaking.

Development stage property. A property with disclosed coal reserves but no material extraction.

ESG. Environmental, social and governance sustainability criteria.

Exploration stage property. A property with no disclosed coal reserves.

High-Vol. A. A coking coal used in steel production with a volatile matter content generally between 31% and 34.5% on a dry basis.

High-Vol. B. A coking coal used in steel production with a volatile matter content generally between 34.5% and 38% on a dry basis.

Indicated coal resource. That part of a coal resource for which quantity and quality are estimated on the basis of adequate geological evidence and sampling sufficient to establish geological and quality continuity with reasonable certainty.

Inferred coal resource. That part of a coal resource for which quantity and quality are estimated on the basis of limited geological evidence and sampling sufficient to establish that geological and quality continuity are more likely than not. Given the higher level of geological uncertainty, inferred coal resources are not considered when assessing the economic viability of a mining project or determining coal reserves.

Initial assessment. A preliminary technical and economic study of the economic potential of all or parts of mineralization to support the disclosure of mineral resources.

In situ coal resources. Coal resources stated on an in-seam dry basis (excluding surface and inherent moisture) with no consideration for dilution or losses that may occur when coal is mined or extracted.

Longwall mining. The most productive underground mining method in the United States. A rotating drum is advanced mechanically across the face of coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface.

Low-Vol. A coking coal used in steel production with a volatile matter content generally between 16% - 23% on a dry basis.

Marketable coal reserves. Coal reserves on a moist basis (including surface and inherent moisture) after considering dilution and losses that may occur when coal in mined or extracted.

Measured coal resource. That part of a coal resource for which quantity and quality are estimated on the basis of conclusive geological evidence and sampling sufficient to test and confirm geological and quality continuity.

Merger. Merger with ANR, Inc. and Alpha Natural Resources Holdings, Inc. completed on November 9, 2018.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, its quality is primarily differentiated based on volatility or its percent of volatile matter. Met coal typically has a particularly high BTU but low ash and sulfur content.

Mid-Vol. A coking coal used in steel production with a volatile matter content generally between 23% -31% on a dry basis.

MSHA. The United States Mine Safety and Health Administration, which has responsibility for developing and enforcing

safety and health rules for U.S. mines.

Northern Appalachia or NAPP. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

Operating Margin. Coal revenues less cost of coal sales.

Powder River Basin or PRB. Coal producing area in northeastern Wyoming and southeastern Montana.

Pre-feasibility study. A comprehensive study of a range of options for the technical and economic viability of a mineral project that has advanced to a stage where a preferred method of mining or pit configuration, an effective method of mineral processing and an effective plan to sell the product has been determined.

Preparation plant. A preparation plant is a facility for crushing, sizing and washing coal to remove impurities and prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content. A preparation plant is usually located on a mine site, although one plant may serve several mines.

Probable mineral reserve. The economically mineable part of an indicated and, in some cases, a measured coal resource.

Production stage property. A property with material extraction of coal reserves.

Productivity. As used in this report, refers to clean metric tons of coal produced per underground man hour worked, as published by MSHA.

Proven mineral reserve. The economically mineable part of a measured coal resource.

Qualified person. A mineral industry professional as defined in subpart 1300 of Regulation S-K.

Reclamation. The process of restoring land and the environment to their original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually under way before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil.

Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is equal to 2,240 pounds; a “metric” ton (or “tonne”) is approximately 2,205 pounds. Tonnage amounts are stated in short tons, unless otherwise indicated.

UMWA. United Mine Workers of America.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car and conveyor to the surface.

Item 1. Business

We are a Tennessee-based mining company with operations in Virginia and West Virginia. With customers across the globe, high-quality reserves and significant port capacity, we reliably supply metallurgical coal products to the steel industry. We operate highly productive, cost-competitive coal mines across the CAPP coal basin. Our portfolio of mining operations consists of 14 active underground mines, five active surface mines and eight active coal preparation plants, as well as one underground mine, one surface mine, and one coal preparation plant that have been temporarily idled. We own a 65.0% interest in Dominion Terminal Associates (“DTA”), a coal export terminal in Newport News, Virginia. DTA provides us with the ability to fulfill a broad range of customer coal quality requirements through coal blending, while also providing storage capacity and transportation flexibility.

We predominantly produce metallurgical (“met”) coal, which is shipped to domestic and international steel and coke producers. Although our strategic focus is on the production of met coal, we also produce thermal coal as byproduct and it is primarily sold to large utilities and industrial customers both in the United States and across the world. Refer to Notes 21 and 22 to the Consolidated Financial Statements for geographical information about our coal sales and additional segment information.

We have a substantial reserve base of 294.5 million tons of proven and probable reserves as of December 31, 2025. Our reserve base consists of 282.8 million tons of proven and probable metallurgical reserves, and 11.7 million tons of proven and probable thermal reserves.

Through our operations, we are able to source coal from multiple mines to meet the needs of a long-standing global customer base, many of which have been served by us or our predecessors for decades. We are continuously evaluating opportunities to strategically cultivate current relationships to drive new business in our target growth markets. In addition, our experienced management team regularly analyzes potential acquisitions, joint ventures and other opportunities that would be accretive and synergistic to our existing asset portfolio.

In 2025, due to continued softness in the met coal pricing environment, especially for U.S. High-Vol. products driven by weak global steel demand combined with additional U.S. High-Vol. production, we reduced production levels at our Jerry Fork and Black Eagle mines within our Power Mountain and Marfork mining complexes, respectively, and temporarily idled our Long Branch surface mine within our McClure/Toms Creek mining complex. For more information refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.”

In 2024, we began the development phase for our new Kingston Wildcat underground mine located in Fayette County, West Virginia. The mine, which will produce a Low-Vol. quality met coal, is expected to begin production in the first quarter of 2026.

In November 2024, due to a softening in the met coal pricing environment, we temporarily idled our Elk Run mining complex. Its Checkmate Powellton mine, which had recently begun production and had not yet reached planned production levels, had relatively higher costs. The mine is being maintained and is expected to be restarted once market conditions improve.

In 2023, we completed development of and commenced production at our Rolling Thunder and Checkmate Powellton mines within our Power Mountain and Elk Run mining complexes, respectively, which produce High-Vol. B quality met coal from the Powellton coal seam.

We were formed in 2016 to acquire and operate certain of Alpha Natural Resources, Inc.’s former core coal operations, as part of the Alpha Natural Resources, Inc. Plan of Reorganization.

On November 9, 2018, we merged with Alpha Natural Resources Holdings, Inc. and ANR, Inc. Upon the consummation of the transactions contemplated by a definitive merger agreement (the “Merger Agreement”), our common stock began trading on the New York Stock Exchange under the ticker “CTRA.” Previously, our shares traded on the OTC market under the ticker “CNTE.”

The following table provides a summary of information regarding our active and temporarily idled mining complexes as of December 31, 2025 (refer to “Item 2. Properties” for further information):

(1)     Number of active or temporarily idled mines as of December 31, 2025.

(2)     Equipment: CM = Continuous Miner; S = Shovel/Excavator/Loader/Trucks; H = Highwall Miner

(3)     CSX = CSX Transportation; NS = Norfolk Southern Railway Company

(4)     Tons of coal purchased from third parties and not processed are not included.

(5)     Net book value of property, plant and equipment and owned and leased mineral rights as of December 31, 2025.

(6)     Proven and probable reserves as of December 31, 2025. Refer to “Item 2. Properties” for further information. Feasibility/pre-feasibility study not considered cost beneficial for Power Mountain complex.

Aracoma – Aracoma is a mining complex located in Logan, Mingo, and Boone counties, West Virginia. The complex has three active underground mines which produce primarily High-Vol. B quality met coal from the Upper Chilton, Upper Cedar Grove, and No. 2 Gas coal seams. Mine lives range from 4 to 13 years. Coal is processed at the Bandmill Preparation Plant and loaded onto CSX rail for delivery to customers.

Kepler – Kepler is a mining complex located in Wyoming and McDowell counties, West Virginia. The complex has one active underground mine (with an estimated life of 12 years) which produces primarily Low-Vol. quality met coal from the Pocahontas No. 3 coal seam. Coal is processed at the Kepler Preparation Plant and either loaded onto NS rail or trucked to the Feats Loadout and loaded onto the CSX rail for delivery to customers.

Kingston/Mammoth – Kingston/Mammoth is a mining complex located in Fayette and Raleigh counties, West Virginia. The complex has one active underground mine, which produces primarily Mid-Vol. quality met coal from the Douglas coal seam. The complex also has two active surface mines which produce High-Vol. A quality met coal as well as some thermal quality coal as a by-product of mining from multiple coal seams. Mine lives range from 2 to 11 years. Coal from the underground mine is processed at the Kingston Preparation Plant and trucked to the Pax Loadout to be loaded onto CSX rail for delivery to customers. Coal from the surface mines may be processed through the Kingston Preparation Plant, trucked to and processed through the Mammoth Plant, or trucked directly to the Pax Loadout or Marmet Dock for delivery to customers.

During 2024, development began on a new Wildcat underground mine (with an estimated life of 11 years) which will produce Low-vol. quality met coal from the Sewell coal seam. Coal is expected to be short-line railed to and processed through the Mammoth plant to be loaded onto NS rail for delivery to customers. Production is expected to begin in the first quarter of 2026.

Marfork – Marfork is a mining complex located in Raleigh, Boone, Kanawha, and Fayette counties, West Virginia. The complex has three active underground mines which produce High-Vol. A quality met coal from the Eagle coal seam and one active underground mine that produces mid-vol quality met coal from the Glen Alum Tunnel seam. The complex also has two active surface mines which produce High-Vol. A quality met coal as well as some thermal quality coal as a by-product of mining from multiple coal seams. Mine lives range from 1 to 12 years. Coal from the underground mines is processed at the Marfork Preparation Plant and loaded onto the CSX rail for delivery to customers. Coal from the surface mines may be processed through the Marfork Preparation Plant or trucked directly to the Pax Loadout or the Marmet Dock for delivery to customers.

McClure/Toms Creek – McClure/Toms Creek is a mining complex located in Dickenson, Buchanan, Russell, and Wise counties, Virginia. The complex has three active underground mines which produce High-Vol. A and Mid-Vol. quality met coal from the Upper Banner, Lower Banner, and Jawbone coal seams. The complex also has one active surface mine and one idle surface mine which produce primarily High-Vol. A quality met coal as well as some thermal quality coal as a by-product of mining from multiple coal seams. Mine lives range from 1 to 22 years. Coal is processed at either the McClure Preparation Plant or the Toms Creek Preparation Plant and loaded on the CSX or NS rail, respectively for delivery to customers.

Power Mountain – Power Mountain is a mining complex located in Nicholas and Clay counties, West Virginia. The complex has two active underground mines (with estimated lives of 3 and 18 years) which produce High-Vol. B quality met coal. Coal from one mine, produced from the Eagle coal seam, is processed at the Power Mountain Preparation Plant and loaded onto NS rail for delivery to customers. Coal from the other mine, produced from the Powellton coal seam, is currently trucked to and processed through the Mammoth Preparation Plant. Following the future development of a haul road, coal is expected to also be processed through the Power Mountain Preparation Plant.

Elk Run – Elk Run is a mining complex located in Boone County, West Virginia. In December 2023, production began at an underground mine which produces High-Vol. B quality met coal from the Powellton coal seam. Coal from the mine was processed at the Chess Processing Plant and loaded onto CSX rail for delivery to customers. In November 2024, the complex was temporarily idled due to a softening in the met coal pricing environment combined with the relatively higher cost nature of the Checkmate Powellton mine, as it remained in its early start-up period and had not yet reached planned production levels. The mine (which has an estimated life of 24 years) and complex are expected to resume operation once market conditions have improved.

Our plant and equipment, including underground and surface equipment, are of varying age, in good operational condition, and are regularly maintained and serviced by a dedicated maintenance workforce and third-party suppliers, including scheduled preventive maintenance.

The following is a summary of information regarding our active and temporarily idled preparation plants as of December 31, 2025:

(1)     Plant was refurbished in 2023, began processing coal in the first quarter of 2024, and was temporarily idled in the fourth quarter of 2024.

The following is a summary of information regarding our active loadouts and docks as of December 31, 2025:

The following is a summary of information regarding DTA (in which we own a 65% interest) as of December 31, 2025:

We use four different mining techniques to extract coal from the ground: room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining, contour mining, and highwall mining. We do not use mountaintop removal mining and currently have no plans to do so in the future.

Certain of our mines use room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from the seam, leaving pillars to support the roof. Shuttle cars or battery coal haulers are generally used to transport coal from the continuous miner to the conveyor belt for transport to the surface. This method is more flexible than longwall mining and often used to mine smaller coal blocks or thinner seams of coal. Ultimate seam recovery of in-place reserves is less than that achieved with longwall mining. All of this production is also processed in preparation plants to remove rock and impurities before it becomes saleable clean coal.

We utilize truck/shovel and truck/front-end loader mining methods at some of our surface mines. These methods are similar and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders to remove earth and rock (overburden) covering a coal seam that is later used to refill the excavated coal pits after the coal is removed. The loading equipment places the coal into trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%.

Depending on geology and market destination, surface-mined coal may need to be processed in a preparation plant before sale. In the case of some metallurgical grade coals, as much as 80% of surface mined coal may need to be processed in a preparation plant to enhance the sales value of the coal. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.

We use contour mining at certain of our surface mines, which limits the overburden removal from above a coal seam or series of coal seams. In contour mining, surface mining machinery follows the contours of a coal seam or seams around a ridge, excavating the overburden and recovering the coal seam or seams as a “contour bench” around the ridge is created. This contour bench is then backfilled and graded in accordance with an approved reclamation plan. Highwall mining methods are used in connection with some contour mining operations. Depending on geology and market destination, coal mined by contour mining may need to be processed in preparation plants to remove rock and impurities before it becomes a saleable clean coal.

We utilize highwall mining methods at certain of our surface mines. A highwall mining system consists of a remotely controlled continuous miner, which extracts coal and conveys it via augers or belt conveyors to the surface. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 9-feet or 11-feet wide and reaching depths of up to 1,000 feet. Multiple parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole. All of the coal mined at our highwall mining operations is processed in preparation plants to remove rock and impurities before it becomes saleable clean coal.

As of December 31, 2025, we have one reportable operating segment: Met. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition—Results of Operations” and Notes 21 and 22 to the Consolidated Financial Statements for financial information about our reportable segment and geographic areas.

We market coal produced at our operations and purchase and resell coal mined by others. We have coal supply commitments with a wide range of steel and coke manufacturers, industrial customers, and electric utilities. Our marketing efforts are centered on meeting customer needs and requirements. By offering coal of various grades, we are able to provide the specific qualities relevant to our customers and to serve a global customer base. Through this global platform, our coal is shipped to customers on five continents. Our broad customer and product base allows us to adjust to changing market conditions. Many of our larger customers are well-established steel manufacturers and public utilities.

Our coal volumes include coal produced and processed by us, our “captive coal,” as well as coal purchased from third-party producers to blend with our produced coal in order to meet customer specifications. These volumes are processed by us, meaning that we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale. Our coal volumes within our Met segment operations also include met coal volumes purchased from domestic third-party producers and sold into international markets.

Our export shipments serviced customers in 19 and 26 countries during the years ended December 31, 2025 and 2024, respectively. Asia was our largest export market for the years ended December 31, 2025 and 2024, with coal sales to Asia accounting for approximately 45% and 43%, respectively, of export coal revenues and 33% and 34%, respectively, of coal revenues in each year. All of our sales are conducted in U.S. dollars. Refer to Note 21 to the Consolidated Financial Statements for additional export coal revenue information.

Met coal accounted for approximately 96% and 97%, respectively, of our coal revenues for the years ended December 31, 2025 and 2024. Our met coal sales are typically made to customers with whom we have a long-term relationship. Domestic met customers typically enter into one-year agreements with a fixed price for the entire contract year. Any longer-term agreement would generally have a renegotiation of price each subsequent contract year. Export sales are generally made on an annual, quarterly, or spot cargo basis. Annual and quarterly agreements typically have market-indexed pricing that changes with the market monthly. Any export agreement with a term greater than one year would generally have a renegotiation of pricing terms for each subsequent contract year. Volume for future years is generally contingent on both parties agreeing to a pricing mechanism to cover the contract year. Thermal coal accounted for approximately 4% and 3%, respectively, of our coal revenues for the years ended December 31, 2025 and 2024.

We sometimes enter into long-term contracts with our coal customers. Terms of these agreements may address coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, force majeure, suspension, termination and assignment issues, the allocation between the parties of the cost of complying with future governmental regulations and many other matters.

Generally, our long-term thermal coal agreements contain committed volumes and fixed prices for a period or a certain number of periods pursuant to which thermal coal will be delivered under these agreements. After a fixed price period elapses, the long-term agreement may provide for a price negotiation/determination period prior to the commencement of the pending unpriced contract period. The price negotiations generally consider either then current market prices and/or relevant market indices. Provisions of this sort increase the difficulty of predicting the exact prices a coal supplier will receive for its coal during the course of the long-term agreement. During the years ended December 31, 2025 and 2024, approximately 60% and 63%, respectively, of our met coal sales volume was delivered pursuant to long-term contracts. During the years ended December 31, 2025 and 2024, approximately 65% and 24%, respectively, of our thermal coal sales volume was delivered pursuant to long-term contracts.

Coal consumed domestically is usually sold at the mine and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers responsible for further transportation.

For our export sales, we negotiate transportation agreements with various providers, including railroads, trucks, barge lines, and terminal facilities to transport shipments to the relevant loading port. We coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet each customer’s needs. Our captive coal is loaded from our preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase is loaded in some cases directly from mines and preparation plants operated by third parties or from an export terminal. Virtually all of our coal is transported from the mine to our preparation plants by truck or belt conveyor systems. It is transported from preparation plants and loading facilities to the customer by means of railroads, trucks, barge lines, and lake-going and ocean-going vessels from terminal facilities. We depend upon rail, barge, trucking and other systems to deliver coal to markets. In the years ended December 31, 2025 and 2024, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation and Norfolk Southern Railway Company. Rail shipments constituted approximately 89% and 90% of total shipments of coal volume from our mines during the years ended December 31, 2025 and 2024, respectively. The balance was shipped from our preparation plants, loadout facilities or mines via truck or barge. Our export sales are primarily shipped to DTA and Pier 6 (Lambert’s Point) shipping ports in the Hampton Roads area of Virginia. We may ship limited export quantities through other U.S. ports when warranted by logistics and economics.

Principal goods and services used in our business include mining equipment, replacement parts and materials such as explosives, diesel fuel, tires, conveyance structure, ventilation supplies, lubricants, steel, magnetite and other raw materials, maintenance and repair services, electricity, and roof control and support items. We rely substantially on third-party suppliers to provide mining materials and equipment. Although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies, we believe that adequate substitute suppliers are available.

We incur substantial expenses each year to procure goods and services in support of our respective business activities in addition to capital expenditures. We use suppliers for a significant portion of our equipment rebuilds and repairs, as well as construction and reclamation activities.

We have a centralized sourcing group, which sets sourcing policy and strategy focusing primarily on major supplier contract negotiation and administration, including but not limited to the purchase of major capital goods in support of the mining operations. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs while improving quality and service. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

The coal industry is highly competitive, both in the U.S. and internationally. We produced approximately 13.7 million tons of met coal in 2025. At the time of filing, certain industry data for 2025 was unavailable due to a distribution delay resulting from U.S. government shutdowns. Of the approximately 73.1 million tons of met produced in the U.S. in 2024, we produced approximately 14.6 million tons, or 20%. A significant portion of U.S. met coal production is shipped internationally, where it competes directly with international sources of production. Approximately 76% and 77% of our met coal tons sold were shipped internationally in 2025 and 2024, respectively.

We produced approximately 1.2 million tons of thermal coal in 2025. At the time of filing, certain industry data for 2025 was unavailable due to a distribution delay resulting from U.S. government shutdowns. Of the approximately 435.7 million tons produced in the U.S. in 2024, we produced approximately 1.1 million tons, or less than 1%. Only a small portion of overall U.S. thermal production is shipped internationally, but there is strong competition in the domestic market. Approximately 65% and 70% of our thermal coal tons sold were shipped internationally in 2025 and 2024, respectively. We compete for U.S. sales with numerous coal producers in the Appalachian region and the Illinois basin, and in some cases with western coal producers.

Demand for met coal and the prices that we are able to obtain for it depend to a large extent on the demand and price for steel in the U.S. and internationally. This demand is influenced by factors beyond our control, including overall economic activity and the availability and relative cost of substitute materials. In the export met coal market, we compete with producers from Australia and Canada and with other international producers on many of the same factors as in the U.S. market. Competition in the export market is also affected by fluctuations in relative foreign exchange rates and costs of inland and ocean transportation, among other factors.

Demand for thermal coal and the prices that we are able to obtain for it are closely linked to coal consumption patterns of the domestic electric generation industry. These coal consumption patterns are influenced by many factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures, and commercial and industrial outputs in the U.S., environmental and other government regulations, technological developments and the location, availability, quality and price of competing sources of power. These competing sources include natural gas, nuclear, fuel oil and increasingly, renewable sources such as solar and wind power. Demand for thermal coal and the prices that we are able to obtain for it are affected by each of the above factors.

As of December 31, 2025, we had approximately 3,960 employees, all of which were full-time employees, with 74% of our total workforce being hourly workers. Our employees were almost entirely located in the United States, with three employees located outside the United States. Approximately 97% of our total workforce was union-free as of December 31, 2025. Certain of our subsidiaries have wage agreements with the UMWA representing roughly 3% of our workforce. These agreements are subject to termination by either the employer or the UMWA, without cause, on July 31, 2028 and one on February 28, 2026. An agreement to succeed the latter is currently being negotiated. We strive to maintain positive working relationships with organized labor. Relations with our employees are important to our success, and we believe that we have good relations with our workforce.

As of December 31, 2025, we had approximately 3,720 employees working at our mining operations across Central Appalachia in Virginia and West Virginia, while the remainder of our personnel were employed at our headquarters in Bristol, Tennessee, in Julian, West Virginia, or at other administrative offices throughout the region. As of December 31, 2025, approximately 36% of our total workforce had at least ten years of service with our Company, while approximately 27% had fifteen or more years of service with our Company.

We require a skilled workforce with mining experience and proficiency as well as qualified managers and supervisors to run our business. In addition, we depend on the experience and industry knowledge of our officers and other key employees to design and execute our business plans. We, along with the mining industry generally, face a shortage of skilled and experienced employees. Therefore, we offer employees competitive compensation and benefits to attract and retain a skilled and qualified workforce. We offer our employees competitive fixed base pay; a bonus incentive program for administrative positions tied to company safety, environmental stewardship, and financial performance; an operations bonus incentive program tied to site-specific safety, environmental stewardship and production goals; paid time-off including holidays; a comprehensive benefits package that includes medical, dental, and vision coverage; disability and life insurance coverages; and a 401(k) retirement savings program with an employer match. All employees have access to our Employee Assistance Program at no cost, which gives them and their family access to licensed professionals for help with mental health, stress, addiction, grievances, relationship issues, childcare and eldercare services, legal and personal finance services and other work/life balance matters.

To help retain key employees in certain positions, our long-term incentive program awards cash or equity grants with time-based and performance-based vesting conditions. Certain key employees are also eligible to participate in our non-qualified deferred compensation plan.

At Alpha, we strive to maintain a positive culture where employees can contribute their best work, take pride in doing the right thing, and work to improve and strengthen the organization. To have a successful operation, we endeavor to establish and maintain relationships with and among our employees that are built upon mutual respect, trust, and appreciation.

Due to the industry shortage of skilled and experienced employees, we have an extensive in-house apprentice miner training program. Selected participants are given robust safety and mining training over a six-month period in order to obtain their required miner’s certification. We frequently provide training opportunities for operations employees to obtain certifications for Emergency Medical Technician, Mechanical Engineering Technology, foreman and supervisory certifications, and electrical certifications in addition to providing apprentice miner training and supervisor training programs.

In addition to various training programs that we require employees in certain skilled positions to complete, all of our employees are provided with employee handbooks and are expected to follow policies and procedures concerning employment matters at Alpha and our affiliates including, but not limited to: anti-harassment, workplace violence, code of business ethics, drug and alcohol policies, safety policies and vehicle policies.

Safety is one of our core values and is the foundation for how we manage every aspect of our business. Our employees are empowered with the skills, training, resources, and responsibility to perform their jobs in a safe manner and are accountable for their own safety as well as the safety of their co-workers. Every employee has a voice in the safety process at each of our mines and other operating sites. Our behavior-based safety process empowers employees to engage in the elimination of at-risk behaviors in the workplace and in incident prevention and continuous improvement. In recognition of the interdependence between safety and operations, our “Safe Production” process promotes the effective utilization of procedures, developing safety action plans at each operating group and sharing of best practices, safety alerts and lessons learned across the entire organization.

Safety leadership and training programs are based upon the concepts of situational awareness and observation, changing behaviors and, most importantly, employee involvement. The core elements of our safety training include identification of critical behaviors and the frequency of those behaviors, employee feedback, and removal of barriers for continuous improvement. All employees are empowered to champion the safety process and are challenged to identify hazards and initiate prompt corrective actions. All levels of the organization are expected to be proactive and commit to continuous improvement and implementation of new safety processes that promote a safe and healthy work environment.

In 2025, we achieved an overall Non-fatal days lost (“NFDL”) safety incident rate that was 38% better than the U.S. industry average NFDL safety incident rate per 200,000 hours worked. The industry rate is based on available data for the first two quarters of 2025 for bituminous coal and the Alpha rate reflects full year 2025. At the time of filing, certain more recent industry data for 2025 was unavailable due to a distribution delay resulting from U.S. government shutdowns. In 2024, we achieved an overall Non-fatal days lost safety incident rate that was 45% better than the U.S. industry average NFDL safety incident rate per 200,000 hours worked. The industry rate is based on the full year 2024 for bituminous coal and the Alpha rate also reflects the full year 2024.

Alpha’s mine operations routinely collaborate with academic institutions as well as federal and state agencies to facilitate testing of new concepts and technologies and to utilize them whenever possible to provide the best safety and protection for our employees.

We also believe in taking precautions to avoid incidents and prevent them from occurring. Our Incident Response Plan and Mine Emergency Response Drills have been developed and widely disseminated to appropriate operations and corporate personnel to build the framework for a prompt and coordinated response in the event an incident occurs. Alpha’s award winning mine rescue teams undergo highly specialized training and compete in regional and national mine rescue events to test their skills in first aid, firefighting, mine ventilation, and critical decision-making.

As posted on our Company website, several of our mine operations have been recognized on numerous occasions for outstanding performance and have received several awards in the areas of safety and mine rescue. In 2025, Alpha mine rescue teams won an overall grand champion award along with several other first-place awards in both overall competition honors and technical category titles.

Refer to Exhibit 95 - Mine Safety Disclosure included as an exhibit to this Annual Report on Form 10-K for additional mine safety information.

We are party to legal proceedings from time to time that occur in the ordinary course of business. These proceedings, as well as governmental examinations, could involve various business units and a variety of claims, including, but not limited to, contract disputes, personal injury claims, property damage claims (including those resulting from blasting, subsidence, trucking and flooding), environmental and safety issues, securities-related matters and employment matters. While some legal matters may specify the damages claimed by the plaintiffs, many seek an unquantified amount of damages. Even when the amount of damages claimed against us or our subsidiaries is stated, (i) the claimed amount may be exaggerated or unsupported; (ii) the claim may be based on a novel legal theory or involve a large number of parties; (iii) there may be uncertainty as to the likelihood of a class being certified or the ultimate size of the class; (iv) there may be uncertainty as to the outcome of pending appeals or motions; and/or (v) there may be significant factual issues to be resolved. As a result, if such legal matters arise in the future, we may be unable to estimate a range of possible loss for matters that have not yet progressed sufficiently through discovery and development of important factual information and legal issues. We record accruals based on an estimate of the ultimate outcome of these matters, but these estimates can be difficult to determine and involve significant judgment. For additional information about our legal proceedings, refer to Note 20, part (d), to the Consolidated Financial Statements.

Federal, state and local authorities regulate the U.S. coal mining industry and the industries it serves with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water quality, plant and wildlife protection, the reclamation of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater quality and availability. These laws and regulations, which are extensive, subject to change, and have tended to become stricter over time, have had, and will continue to have, a significant effect on our production costs and our competitive position relative to certain other sources of electricity generation. Future legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may result in substantial increases in equipment and operating costs and delays, interruptions, or a termination of operations, the likelihood or extent of which we cannot predict. We intend to continue to comply with regulatory requirements as they evolve by timely implementing necessary modifications to facilities or operating procedures. Future legislation, regulations, orders or regional or international arrangements, agreements or treaties, as well as efforts by private organizations, including those relating to global climate change, may continue to cause coal to become more heavily regulated.

We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. We have certain procedures in place that are designed to enable us to comply with these laws and regulations. However, due to the complexity and interpretation of these laws and regulations, we cannot guarantee that we have been or will be at all times in complete compliance, and violations are likely to occur from time to time. None of the violations or the monetary penalties assessed upon us to date have been material. Future liability under or compliance with environmental and safety requirements could, however, have a material adverse effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation, denial or suspension of mining permits, may be imposed under the laws described below.

Monetary sanctions, expensive compliance measures and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

As of December 31, 2025, we had accrued $227.4 million for reclamation liabilities and mine closures, including $22.6 million of current liabilities.

Numerous governmental permits or approvals are required for mining operations pursuant to certain federal, state and local laws applicable to our operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment and measures we will take to minimize and mitigate those impacts. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit the necessary permit applications several months, or even years, before we plan to begin mining a new area. Mining permits generally are approved months or even years after a completed application is submitted. Therefore, we cannot be assured that we will obtain future mining permits in a timely manner.

Permitting requirements also require, under certain circumstances, that we obtain surface owner consent if the surface estate has been severed from the mineral estate. This requires us to negotiate with third parties for surface rights that overlie coal we control or intend to control. These negotiations can be costly and time-consuming, lasting years in some instances, which can create additional delays in the permitting process. If we cannot successfully negotiate for surface rights, we could be denied a permit to mine coal we already control.

Surface Mining Control and Reclamation Act (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection, reclamation, and closure standards for all aspects of surface mining as well as many aspects of underground mining that effect surface expressions. Mine operators must obtain SMCRA permits and permit renewals from the OSM or from the applicable state agency if the state agency has obtained primary control of administration and enforcement of the SMCRA program, or primacy.

A state agency may obtain primacy if OSM concludes that the state regulatory agency’s mining regulatory program is no less stringent than the federal mining program under SMCRA. States where we have active mining operations have achieved primacy and issue permits in lieu of OSM. OSM maintains oversight of how the states administer their programs.

SMCRA permit provisions include a complex set of requirements which include: coal prospecting; mine plan development; topsoil or growth medium removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance, including outside the permit area; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation and reclamation.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes, but is not limited to, surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures associated with the coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the OSM’s Applicant Violator System (“AVS”), including the mining and compliance history of officers, directors and principal owners of the entity.

Regulations under SMCRA and its state analogues provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls us or is under common ownership or control with us have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including being an officer or director of an entity or owning between 10% and 50% of the mining operator. These presumptions, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which the relevant coal mining operation is conducted. Thus, past or ongoing violations of federal and state mining laws by us or by coal mining operations owned or controlled by our significant stockholders, directors or officers or certain other third-party affiliates could provide a basis to revoke existing permits and to deny the issuance of additional permits or modifications or amendments of existing permits. This is known as being “permit-blocked.” In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given, which also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take months or even years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. The current fee, which is effective through September 30, 2034, is $0.224 per ton on surface-mined coal and $0.096 per ton on deep-mined coal. For the years ended December 31, 2025 and 2024, we recorded $1.8 million and $2.0 million, respectively, of expense related to these fees.

While SMCRA is a comprehensive statute, SMCRA does not supersede the need for compliance with other major environmental statutes, including the Endangered Species Act; Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”).

Federal and state laws require us to obtain surety bonds or other approved forms of security to cover the costs of certain long-term obligations, including mine closure or reclamation costs under SMCRA, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. As of December 31, 2025 and 2024, our posted third-party surety bond amount in all states where we operate totaled approximately $170.0 million and $182.8 million, respectively, which was used to primarily secure the performance of our reclamation and lease obligations.

Posting of a bond or other security with respect to the performance of reclamation obligations is a condition to the issuance of a permit under SMCRA. Under the terms of agreements we and Alpha Natural Resources, Inc. entered into in connection with the Alpha Natural Resources, Inc. Restructuring, we and Alpha Natural Resources, Inc. were required to replace Alpha Natural Resources, Inc.’s self-bonds with surety bonds, collateralized bonds, or other financial assurance mechanisms, over time and under applicable regulations. Self-bonding may not be available to us as a means to comply with our reclamation bonding obligations for the foreseeable future. In August 2016, OSM announced its decision to pursue a rulemaking to evaluate self-bonding for coal mines, including eligibility standards. OSM has not yet issued a proposed rule to address this issue.

The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to particulate matter (“PM”), which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating air emissions of PM, sulfur dioxide, nitrogen oxides (“NOx”), mercury and other compounds emitted by coal-fired electricity generating plants or the use of met coal in connection with steelmaking operations. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide, and mercury. The general effect of emission regulations on coal-fired power plants could be to reduce demand for coal.

In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may materially and adversely affect our operations, financial results, liquidity, and demand for coal, directly or indirectly, include, but are not limited to, the following:

•Acid Rain. Title IV of the Clean Air Act requires reductions of sulfur dioxide emissions by electric utilities. Affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels and purchasing or trading sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years.

•NAAQS for Criteria Pollutants. The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for six common air pollutants, including nitrogen oxide, sulfur dioxide, PM, and ozone. Areas that are not in compliance (referred to as “non- attainment areas”) with these standards must take steps to reduce emissions levels. Over the past several years, the EPA has revised its NAAQS for nitrogen oxide, sulfur dioxide, PM and ozone, in each case making the standards more stringent. As a result, some states have been, and will be, required to amend their existing individual state implementation plans (“SIPs”) to achieve compliance with the new air quality standards. Other states will be required to develop new plans for areas that were previously in “attainment,” but do not meet the revised standards. On December 7, 2020, the EPA announced the agency’s final decision to retain the existing National Ambient Air Quality Standards for PM set by the Obama-Biden Administrations in 2012 without changes. However, on January 6, 2023, the EPA proposed to revise the primary (health-based) annual standard for PM2.5, from its then-current level of 12.0 micrograms per cubic meter (µg/m3) to within the range of 9.0 to 10.0 µg/m3. The EPA also proposed revisions to some other provisions of the PM NAAQS, including revisions to the air quality index and monitoring requirements, but did not propose to change other key aspects of the standard: (i) the secondary (welfare-based) annual PM2.5 standard; (ii) the primary and secondary 24-hour PM2.5 standards and (iii) the primary and secondary 24-hour PM10 standards. On February 7, 2024, the EPA revised the primary (health-based) annual standard for PM2.5, from 12.0 µg/m3 to 9.0 µg/m3. The EPA retained the existing primary 24-hour standards for PM2.5 and for PM10, which provides protection against coarse particles. The EPA also did not change the secondary (welfare-based) standards for fine particles and coarse particles.

In October 2015, the EPA finalized the NAAQS for ozone pollution and reduced the standard to 70 parts per billion (ppb) from the previous 75 ppb standard. The EPA made the majority of area designations related to this rule on November 16, 2017 and June 4, 2018 and finalized designations for the remaining regions of the country on July 25, 2018. Under the revised NAAQS for ozone in particular, significant additional emissions control expenditures may be required at coal-fired power plants. The final rules and new standards may impose additional emissions control requirements on our customers in the electric generation, steelmaking, and coke industries. Although coal mining and processing operations may emit certain criteria pollutants, we operate in material compliance with our permits.

However, our operations could be affected if the attainment status of the areas in which we operate changes in the future.

A suit by industry in the D.C. Circuit challenged the EPA’s 2015 Ozone NAAQS (Murray Energy Corp. v. EPA), which resulted in the court upholding the rule with the exception of the secondary NAAQS standards addressing protection of animals, crops and vegetation, which were sent back to the EPA for further consideration. On December 23, 2020, the EPA announced its decision to retain, without changes, the 2015 ozone National Ambient Air Quality Standards set by the Obama-Biden Administration.

•NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrogen oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel. On February 26, 2019, the EPA published a final rule amending the NOx SIP Call regulations to allow states to establish alternative monitoring and reporting requirements for certain sources.

•Cross-State Air Pollution Rule. In June 2011, the EPA finalized the CSAPR, which required 28 states in the Midwest and the eastern seaboard of the U.S. to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Nitrogen oxide and sulfur dioxide emission reductions were scheduled to commence in 2012, with further reductions effective in 2014. However, implementation of CSAPR’s requirements was delayed due to litigation. In October 2014, following a decision from the U.S. Supreme Court, the EPA issued an interim final rule reconciling the CSAPR with the Court’s order, which called for Phase 1 implementation in 2015 and Phase 2 implementation in 2017.

In September 2016, the EPA finalized an update to the CSAPR ozone season program by issuing the Final CSAPR Update rule. The Final CSAPR Update rule was the subject of a challenge in the D.C. Circuit by states and industry stakeholders. In September 2019, the D.C. Circuit concluded that the rule was valid in certain respects but that it failed to ensure that pollution from upwind states would not prevent downwind states from meeting air quality standards in a timely manner. The court directed the EPA to revise the rule to address this failure. On October 15, 2020, the EPA proposed the Revised CSAPR Update rule in order to fully address 21 states’ outstanding interstate pollution transport obligations for the 2008 ozone National Ambient Air Quality Standard. The EPA finalized the Revised CSAPR Update rule on April 30, 2021. The EPA estimated that the Revised CSAPR Update rule would reduce NOx emissions from power plants in 12 states in the eastern United States by 17,000 tons in 2021 compared to projections without the rule, yielding public health and climate benefits that are valued, on average, at up to $2.8 billion each year from 2021 to 2040. An industry group challenged the Revised CSAPR Update rule in the U.S. Court of Appeals for the District of Columbia. On March 3, 2023, the Court rejected this challenge.

On March 15, 2023, the EPA issued its Good Neighbor Plan, a federal implementation plan (“FIP”) designed to replace SIPs submitted by over 20 states to implement their good neighbor obligations with respect to the 2015 ozone NAAQS. The FIP would require significant reductions of ozone-forming NOx emissions from power plants and industrial facilities in 23 states based on the EPA’s determination that these emissions were contributing to the nonattainment of, or problems maintaining the attainment of, the 2015 ozone NAAQs in downwind states. Industry groups and states filed petitions for review in the U.S. Court of Appeals for the D.C. Circuit, challenging the Good Neighbor Plan. States and industry stakeholders also challenged the EPA’s disapproval of SIPs for several states in the regional circuits covering those states and obtained judicial stays of the SIP disapprovals in many states. The EPA’s authority to issue a FIP for a state arises when the state fails to submit a SIP or when the EPA disapproves a SIP. The EPA therefore lacks authority to implement the Good Neighbor FIP in states where its underlying SIP disapproval is stayed. This includes over half of the states that were subject to the Good Neighbor Plan as promulgated. In February 2024, the U.S. Supreme Court heard oral argument on applications for stay of the Good Neighbor Plan, and in June 2024, the Court granted a stay of the Plan pending disposition of the applicants’ consolidated petitions for review of the plan, which remain pending before the U.S. Court of Appeals for the D.C. Circuit but have been held in abeyance based on the EPA’s announcement that it is reconsidering the Good Neighbor Plan and underlying SIP disapprovals.

•Mercury and Hazardous Air Pollutants. In February 2012, the EPA formally adopted a rule to regulate emissions of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal- and oil-fired power plants, referred to as “MATS.” In March 2013, the EPA finalized reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits for new coal-fired units to levels considered attainable by existing control technologies. In subsequent litigation, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration. The D.C. Circuit allowed the current rule to stay in place until the EPA issued a new finding. In April 2016, the EPA issued a final finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. However, in April 2017, the EPA indicated in a court filing that it may reconsider this finding, and on April 27, 2017, the D.C. Circuit stayed the litigation. In August 2018, the EPA announced plans to send a draft proposal to the White House questioning the EPA’s earlier finding.

On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for MATS, as well as the Clean Air Act required “risk and technology review.” After taking account of both the cost to coal- and oil-fired power plants of complying with the MATS rule and the benefits attributable to regulating hazardous air pollutant (“HAP”) emissions from these power plants, the EPA proposed to determine that it is not “appropriate and necessary” to regulate HAP emissions from power plants under Section 112 of the Clean Air Act. The emission standards and other requirements of the MATS rule, first promulgated in 2012, would remain in place, however, since the EPA did not propose to remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112 of the Act.

On April 15, 2020, the EPA established a new subcategory in the MATS for electric utility steam generating units (“EGU’s”) that burn eastern bituminous coal refuse (“EBCR”). Coal refuse includes low-quality coal mixed with rock, clay and other material. The EPA established emission standards for facilities that burn EBCR. This new subcategory and emission standards affected six existing EGUs located in Pennsylvania and West Virginia that burn EBCR.

On May 22, 2020, the EPA published the completed reconsideration of the appropriate and necessary finding for the MATS. The EPA concluded that it is not “appropriate and necessary” to regulate electric utility steam generating units under Section 112 of the Clean Air Act. The EPA also took final action on the residual risk and technology review that is required by the CAA Section 112. The EPA explained, “emissions of HAP have been reduced such that residual risk is at acceptable levels, that there are no developments in HAP emissions controls to achieve further cost-effective reductions beyond the current standard, and, therefore, no changes to the MATS rule are warranted.”

On February 15, 2023, however, the EPA revoked its 2020 finding that it was not appropriate and necessary to regulate coal- and oil-fired power plants under Section 112 of the Clean Air Act, which regulates HAP emissions. The EPA reviewed the 2020 finding and stated that it considered updated information on both (i) the public health burden associated with HAP emissions from coal- and oil-fired power plants; and (ii) the costs associated with reducing those emissions under the MATS rule. On April 3, 2023, the EPA issued a proposed rule that the EPA said would strengthen and update the MATS for power plants to reflect recent developments in control technologies and the performance of these plants. The EPA issued a final revised MATS rule for EGUs in April 2024 that established more stringent standards than the previous rule. Several states and industry stakeholders have challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and that litigation is being held in abeyance at the request of the parties. In June 2025, the EPA published a proposed rule to repeal certain parts of the 2024 rule.

Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA (and in particular, the reconsideration by the current EPA of any rulemaking relating to the MATS rule during the prior presidential administration), states, Congress, or pursuant to an international treaty may further decrease the demand for coal. Like CSAPR, MATS and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants, in addition to the significant number of plants and units that have already been retired as a result of environmental and regulatory requirements and uncertainties adversely impacting coal-fired generation. Such retirements would likely adversely impact our business.

•Regional Haze, New Source Review and Methane. The EPA’s regional haze program is intended to protect and improve visibility at and around national parks, national wilderness areas and international parks. In December 2011, the EPA issued a final rule under which the emission caps imposed under CSAPR for a given state would supplant the obligations of that state with regard to visibility protection. In May 2012, the EPA finalized a rule that allows the trading programs in CSAPR to serve as an alternative to determining source-by-source Best Available Retrofit

Technology (“BART”). This rule provides that states in the CSAPR region can substitute participation in CSAPR for source-specific BART for sulfur dioxide and/or nitrogen oxides emissions from power plants. This program could result in additional emissions restrictions and the need to install additional control measures designed to limit haze causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could contribute to additional coal plant closures and affect the future market for coal. A final Regional Haze rule was published on January 10, 2017 that allowed states to submit their SIP revisions by July 2021. In August 2022, the EPA issued a “finding of failure” to submit complete regional haze SIPs for 15 states, starting a two-year clock for the EPA to issue a FIP for any state that does not submit a revised SIP and have it approved before the FIP is issued. In March 2025, the EPA announced plans to restructure the regional haze program. In the months that followed, the EPA approved Regional Haze SIP revisions for a number of states. Environmental groups have filed lawsuits in the Fourth and Sixth Circuits, challenging the EPA’s approval of West Virginia’s and Ohio’s SIPs, respectively. In October 2025, the EPA issued an advance notice of proposed rulemaking (“ANPR”) seeking public comments on ways to clarify and streamline states’ obligations under the program. Comments on the ANPR closed on December 1, 2025.

In addition, the EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants.

Litigation seeking to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from sources of methane and other emissions related to coal mines was dismissed by the D.C. Circuit in May 2014. In that case, the Court denied a rulemaking petition citing agency discretion and budgetary restrictions, and ruled that the EPA has reasonable discretion to carry out its delegated responsibilities, which include determining the timing and relative priority of its regulatory agenda. In July 2014, the D.C. Circuit denied a petition seeking a rehearing of the case en banc. Litigation regarding these issues may continue and could result in the need for additional air pollution controls for coal-fired units and our operations.

Global climate change initiatives and public perceptions have resulted, and are expected to continue to result, in decreased coal-fired power plant capacity and utilization, phasing out and closing many existing coal-fired power plants, reducing or eliminating construction of new coal-fired power plants in the United States and certain other countries, increased costs to mine coal and decreased demand and prices for thermal coal.

There are three important sources of GHGs associated with the coal industry: first, the end use of our coal by our customers in electricity generation, coke plants, and steelmaking is a source of GHGs; second, combustion of fuel for mining equipment used in coal production; and third, coal mining can release methane, a GHG, directly into the atmosphere. GHG emissions from coal consumption and production are subject to pending and proposed regulation as part of initiatives to address global climate change.

The Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the “Kyoto Protocol”) became effective in 2005 and bound those developed countries that ratified it (which the U.S. did not do) to reduce their global GHG emissions. In December 2015, the United States and almost 200 nations agreed to the Paris Agreement, which entered into force on November 4, 2016 and has the long-term goal to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-industrial era. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, the first Trump administration announced that the U.S. would withdraw from the Paris Agreement. This withdrawal formally took effect on November 4, 2020. However, on February 19, 2021, the U.S. formally rejoined the Paris Agreement. On January 20, 2025,

President Trump signed an executive order requiring the U.S. Ambassador to the United Nations to submit formal written notification of the United States’ withdrawal from the Paris Agreement. The Glasgow Climate Pact reached at the 2021 United Nations Climate Change Conference (COP26), though not legally binding, contains a plan to reduce use of coal by 40%. The COP28 United Nations Climate Change Conference was held in Dubai, the United Arab Emirates, held from November 30 to December 13, 2023. COP28 was intended to evaluate the world’s efforts to address climate change under the Paris Agreement. At the end of the COP28 conference, the participating countries agreed to a call on governments worldwide to speed up the transition away from fossil fuels to renewables such as wind and solar power. These commitments and agreements could further reduce demand and prices for our coal.

In 2009, the EPA issued a finding that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment. The EPA has since adopted regulations under existing provisions of the CAA pursuant to this finding.

For example, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the U.S., including coal-fired electric power plants and steel-making operations. The EPA has also promulgated the Tailoring Rule, which requires that all new or modified stationary sources of GHGs that will emit more than 75,000 tons of carbon dioxide per year and are otherwise subject to CAA regulation, and any other facilities that will emit more than 100,000 tons of carbon dioxide per year, to undergo prevention of significant deterioration (“PSD”) permitting, which requires that the permitted entity adopt the best available control technology.

In June 2014, the U.S. Supreme Court addressed whether the EPA’s regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the CAA as well as the validity of the Tailoring Rule under the CAA. The decision reversed, in part, and affirmed, in part, a 2012 D.C. Circuit decision that upheld the Tailoring Rule. Specifically, the Court held that the EPA exceeded its statutory authority when it interpreted the CAA to require PSD and Title V permitting for stationary sources based on their potential GHG emissions. However, the Court also held that the EPA’s determination that a source already subject to the PSD program due to its emission of conventional pollutants may be required to limit its GHG emissions by employing the “best available control technology” was permissible. As a result, the EPA began requiring new sources already subject to the PSD program, including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for-and so discourage development of-coal-fired power plants. In July 2025, the EPA published a proposed rule that would repeal the 2009 endangerment finding. EPA Administrator Lee Zeldin signed the final rule repealing the endangerment finding on February 12, 2026. We anticipate that the final rule, once published in the Federal Register, will be the subject of widespread litigation.

On August 3, 2015, the EPA released a final rule establishing New Source Performance Standards (“NSPS”) for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired electric generating units (“Power Plant NSPS”). The final rule requires that newly constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb CO2/MWh-gross. The standard is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture and storage (“CCS”). Modified and reconstructed fossil fuel fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance.

Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross). Numerous legal challenges to the final rule were filed in the U.S. Court of Appeals for the D.C. Circuit but the litigation has been held in abeyance since 2017, when the first Trump Administration announced plans to review the final rule.

In August 2015, the EPA issued the Clean Power Plan (“CPP”), a final rule that establishes carbon pollution standards for existing power plants, called CO2 emission performance rates. The EPA expected each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The CPP was immediately subject to legal challenges and was stayed before it was implemented. On July 8, 2019, the EPA, published the ACE Rule, a replacement of the CPP. In contrast to the CPP, which called for the shifting of electricity generation away from coal-fired sources toward natural gas and renewables, the ACE Rule focuses on reducing GHG emissions from existing coal-fired plants by requiring states to mandate the implementation of a range of technologies at power plants designed to improve their heat rate (i.e., decrease the amount of fuel necessary to generate the same amount of electricity). However, on January 19, 2021, the Court of Appeals of the District of Columbia struck down the ACE rule. In May 2024, the EPA issued a final rule known as the GHG Power Plant Rule that requires stringent reductions in carbon dioxide emissions from existing coal-fired plants and relies heavily on the use of CCS. Numerous petitions for review of the final rule were filed in the U.S. Court of Appeals for the D.C. Circuit and are being held in abeyance at the request of the parties. In June 2025, the EPA published a proposed rule to repeal all GHG emissions standards for fossil fuel-fired power plants. A final rule is likely to be published in the first half of 2026. More stringent standards for carbon dioxide emissions as a result of these rulemakings could further reduce demand for coal, and our business would be adversely impacted.

The United States Congress has, from time to time, considered legislation to reduce GHG emissions, such as a resolution referred to as the Green New Deal, which was introduced in the U.S. House of Representatives in February 2019 and similar legislation may be introduced in the current Congressional term. To date, Congress has not passed a bill specifically addressing GHG regulation. In addition, various states and regions have adopted initiatives to reduce, and in some cases phase out, GHG emissions and certain governmental bodies, including the states of Virginia and California, have considered or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. For example, on September 10, 2018, California adopted a law that requires all electricity consumed by the state to be generated from renewable sources such as solar, wind and hydropower by 2045.

On October 7, 2023, California Governor Gavin Newsom signed three landmark climate disclosure bills that are more stringent than the proposed U.S. Securities and Exchange Commission (“SEC”) rules. California’s group of new laws address (i) GHG emissions reporting in compliance with the Greenhouse Gas Protocol (“GHG Protocol”), (ii) climate-related financial risk reporting in accordance with the recommendations of the Task Force on Climate-Related Financial Disclosures (“TCFD”), and (iii) disclosure of information about certain emissions claims and the sale and use of carbon offsets. Although the SEC’s climate disclosure proposal includes GHG Protocol and TCFD requirements, unlike the SEC’s proposed rule, the California requirements apply to certain private and public companies with business activities in California. AB 1305 addresses voluntary carbon market disclosures. It applies to entities that (i) operate and make emissions claims within California; or (ii) buy or sell carbon offsets within California. SB 253 is the Climate Corporate Data Accountability Act. It applies only to business entities with annual revenue over $1 billion that do business in California. It requires disclosure of scope 1, scope 2, and scope 3 GHG emissions. Annual reporting of scope 1 and scope 2 GHC emissions will be required for covered entities beginning in 2026 (for the 2025 fiscal year). Annual reporting of scope 3 GHG emissions will be required beginning in 2027. SB 261 addresses climate-related financial risks of greenhouse gases. It applies to business entities that do business in California if their annual revenue exceeds $500 million. Disclosure will be required on or before January 1, 2026 and biennially thereafter. We currently do not do business in California.

In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely affect the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.

Furthermore, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, could cause coal prices and sales of our coal to materially decline and possibly increase our operating costs.

These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.

The CWA and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Legislation that seeks to clarify the scope of CWA jurisdiction has also been considered by Congress. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements.

CWA requirements that may directly or indirectly affect our operations include the following:

Prior to discharging any pollutants into waters of the United States, coal mining companies must obtain a National Pollutant Discharge Elimination System (“NPDES”) permit from the appropriate state or federal permitting authority. Section 402 of the CWA creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the NPDES program, and corresponding programs implemented by state regulatory agencies. Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern discharges into waters of the United States. Failure to comply with the CWA or NPDES permits can lead to the imposition of significant penalties, litigation, compliance costs and delays in coal production. Furthermore, the imposition of future restrictions on the discharge of certain pollutants into waters of the United States could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations. For instance, waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load regulations, which may lead to the adoption of more stringent discharge standards for our coal mines and could require more costly treatment.

In addition, when water quality in a receiving stream is of high quality, states are required to conduct an anti-degradation review before approving discharge permits. Anti-degradation policies may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits and may also require more costly treatment.

Many mining activities, including the development of settling ponds and the construction of certain sediment control structures, valley fills and surface impoundments, require permits from the U.S. Army Corps of Engineers (“COE”) under Section 404 of the Clean Water Act (“CWA”). Generally speaking, these Section 404 permits allow the placement of dredge and fill materials into navigable waters of the United States, including wetlands, streams, and other regulated areas. The COE has issued general “nationwide” permits (“NWPs”) for specific categories of activities that are similar in nature and that are determined to have minimal adverse effects on the environment. Permits issued pursuant to NWPs 5, 21, 49 and 50 generally authorize the disposal of dredged or fill material from surface coal mining activities into waters of the United States, subject to certain restrictions. NWPs are typically reissued for a five-year period and require appropriate mitigation, and permit holders must receive explicit authorization from the COE before proceeding with proposed mining activities. On December 27, 2021 (affecting NWP numbers including 5 and 49) and January 13, 2021 (affecting NWP numbers including 21 and 50), the COE published its final rules reissuing and modifying its NWPs. These NWPs now expire on March 14, 2026. The January 13, 2021 final rule finalized the proposed removal of the 300 linear foot limit for losses of stream bed from several of the NWPs. On January 8, 2026, the COE published a final rule in the Federal Register announcing the reissuance of 56 NWPs (including NWPs 5, 21, 49, and 50) and one additional NWP. The NWPs will take effect on March 15, 2026 and will expire on March 15, 2031. Expansion of our mining operations into new areas may trigger the need for individual COE approvals, which could be more costly and take more time to obtain.

In January 2020, the EPA and the COE issued a final rule that attempts to clarify the CWA’s jurisdictional reach over waters of the United States, referred to as the Navigable Waters Protection Rule (“NWPR”). The rule replaced a rule issued in June 2015 by the previous presidential administration, the Clean Water Rule. The Clean Water Rule was the subject of extensive legal challenges, injunctions and administrative action, and was formally repealed in December 2019. After the U.S. District Court for the District of Arizona vacated and remanded the NWPR on August 30, 2021, the EPA and the COE halted implementation of the NWPR nationwide and announced that they were interpreting “waters of the United States” consistent with the pre-2015 regulatory regime. On December 30, 2022, the EPA and COE announced the final Revised Definition of Waters of the United States rule, which reasserts the agencies’ CWA jurisdiction over wetlands and certain ephemeral streams. On January 18, 2023, the rule was published in the Federal Register. The rule was effective on March 20, 2023. Like the NWPR, the Revised Definition of Waters of the United States rule has been the subject of legal challenges. On May 25, 2023, the U.S. Supreme Court’s decision in Sackett v. EPA limited the jurisdiction of the EPA and the COE over wetlands. While the January 18, 2023 rule was not directly before the Court, the Court considered the jurisdictional standards set forth in the rule. In Sackett, the Court held that the Clean Water Act’s use of “waters” encompasses only those relatively permanent, standing or continuously flowing bodies of water forming geographical features that are described in ordinary parlance as streams, oceans, rivers, and lakes.

On August 29, 2023, the EPA and the COE issued a final rule to amend the January 2023 rule, to conform the definition of “waters of the United States” to the Supreme Court’s decision in Sackett. This conforming rule amends the provisions of the January 18, 2023 definition of “waters of the United States” that are invalid under the Supreme Court’s interpretation of the Clean Water Act in the Sackett decision. The final amended conforming rule became effective on September 8, 2023. A notice on the EPA’s website explains that, as a result of ongoing litigation on the January 2023 rule, the EPA and the COE are implementing the January 2023 rule, as amended by the August 2023 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 Supreme Court's decision in Sackett until further notice. On November 20, 2025, the EPA and the COE published a proposed rule in the Federal Register that would further revise the regulations defining the scope of

waters of the United States. The public comment period on the proposed rule ended on January 5, 2026.

On November 3, 2015, the EPA published the final rule for Effluent Limitations Guidelines and Standards (“ELGS”), revising the regulations for the Steam Electric Power Generating category, which became effective on January 4, 2016. It established the first federal limits on the levels of arsenic, mercury, selenium and nitrate-nitrites in flue gas desulfurization that can be discharged as wastewater from power plants, based on technology improvements over the last three decades. On April 25, 2017, the EPA stayed the implementation of the rule indefinitely to allow for reconsideration.

On August 31, 2020, the EPA finalized the rule to revise the ELGS. The 2020 rule changed the technology basis for treatment of Flue Gas Desulfurization (“FGD”) Wastewater and Bottom Ash Transport Water (“BATW”). The EPA issued another final rule in May 2024, known as the Supplemental ELG Rule, that further modified the ELGS. The May 2024 rule established zero discharge requirements for BATW, FGD, and combustion residual leachate wastewaters at coal-fueled units with no planned retirement date. Numerous parties filed petitions for review of the 2024 rule, which remain pending in the U.S. Court of Appeals for the Eighth Circuit. In March 2025, the EPA announced its intention to reconsider the rule, and the litigation is being held in abeyance while reconsideration is underway. On December 31, 2025, the EPA published a final rule in the Federal Register extending the deadlines promulgated in the 2024 rule and updating the 2024 rule’s transfer provisions to allow facilities to switch between compliance alternatives.

The ESA and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and mine plan modifications and approvals, and may include restrictions on timber harvesting, road building and other mining activities in areas containing the affected species or their habitats. We may also need to obtain additional permits or approvals if the incidental take of these species in the course of otherwise lawful activity may occur, which could take more time, be more costly and have adverse effects on operations. A number of species indigenous to properties we control or surrounding areas are protected under the ESA including the Guyandotte River Crayfish and the Big Sandy River Crayfish. On January 28, 2020 the U.S. Fish & Wildlife Service (“FWS”) officially published the draft critical habitat designation for the Guyandotte River Crayfish and the Big Sandy River Crayfish in the Federal Register, starting the public comment period on the draft designations. On July 10, 2020, the FWS issued guidance regarding the preparation of protection and enhancement plans (“PEPs”) for coal mining operations located in the Guyandotte River Crayfish habitat in southern West Virginia. The guidance contains several suggestions for requirements to be included in PEPs for proposed mining operations, such as minimizing fill placement, retaining 100 foot vegetative buffers around streams and constructing stream crossings in periods of low flow. The FWS published a final rule on March 15, 2022 designating critical habitat for these species, including approximately 717 stream kilometers in Kentucky, Virginia, and West Virginia. Certain other sensitive species that are not currently protected by the ESA may also require protection and mitigation efforts consistent with federal and state requirements.

After the Stream Protection Rule and the accompanying 2016 Biological Opinion were repealed in February 2017, OSM issued a Section 7(d) determination that reinitiated consultation with the FWS to develop a new Biological Opinion. The new Biological Opinion was released on October 16, 2020. One of the most notable changes is the incidental take coverage if there is no agreement between the state regulatory authority and the FWS at the conclusion of the dispute resolution process and the regulatory authority issues the permit. The new Biological Opinion states that “any prohibited take of listed species incidental to that permit action will not be exempted through this incidental take statement.” The Biological Opinion also includes discussion of OSM enforcement powers in primacy states potentially allowing the FWS to effect a permit veto via OSM enforcement actions. The new Biological Opinion could make the permitting process more difficult and expensive.

RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. In December 2014, the EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rules also require fugitive dust controls and impose various monitoring, cleanup, and closure requirements. In July 2018, the EPA published a final rule extending certain deadlines under the original rules, granting certain authority to states with authorized CCR programs and establishing groundwater protection standards for certain constituents. The EPA and OSM plan additional rulemaking relating to CCR. Most recently, the EPA issued a final rule that took effect in November 2024. That rule applies to inactive surface impoundments at closed facilities, CCR management units (which include impoundments and landfills that were closed before the effective date of the original 2015 CCR Rule), and inactive CCR landfills. Petitions for review of the rule are pending in the U.S. Court of Appeals for the D.C. Circuit but are currently being held in abeyance while the EPA reconsiders the rule. The EPA plans additional rulemaking relating to CCR.

There have also been several legislative proposals that would require the EPA to further regulate the storage of CCR. For example, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which allows states to establish permit programs to regulate the disposal of CCR units in lieu of the EPA’s CCR regulations. These requirements, as well as any future changes in the management of CCR, could increase our customers’ operating costs and potentially reduce their ability or need to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, can lead to material liability for our customers under RCRA or other federal or state laws and potentially further reduce the demand for coal.

CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances into the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on hazardous substance generators, site owners, transporters, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA currently excludes most wastes generated by coal mining and processing operations from the primary hazardous waste laws, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for our current or former owned, leased or operated coal mines and property or those of our predecessors. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we control surface rights. These liabilities could be significant and materially and adversely affect our financial results and liquidity.

Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. For example, pursuant to a rule issued by the U.S. Department of Homeland Security (“DHS”) in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review. In 2011, the DHS published proposed regulations of ammonium nitrate under the Ammonium Nitrate Security Rule. Many of the requirements of the proposed regulations would be duplicative of those in place under the Bureau of Alcohol, Tobacco, Firearms and Explosives, including registration and background checks, and DHS has moved its 2011 rulemaking to a non-active status because the approach proposed was unlikely to deliver appreciable security benefits. Additional requirements may include tracking and verifications for each transaction related to ammonium nitrate. The outcome of these rulemakings could materially adversely affect our cost or ability to conduct our mining operations.

We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substances Control Act and transportation laws adopted to ensure the appropriate transportation of our coal both nationally and internationally. Laws, regulations, and treaties of other countries may also adversely impact our export sales by reducing demand for our coal as a source of power generation in those countries.

Many of our operations use equipment with radioactive sources primarily for coal density measurement. Use of this equipment must be approved by the U. S. Nuclear Regulatory Authority or the state agency that has been delegated this authority.

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (“Mine Act”) significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. All of the states in which we operate also have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and preparation plants and requires the issuance of enforcement action when it is believed that a standard has been violated. While this regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.

In 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act (the “MINER Act”). The MINER Act significantly amended the Mine Act, requiring, among other items, improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since the passage of the MINER Act, enforcement scrutiny has increased, including more inspection hours at mine sites, an increase in the number of inspections and an increase in the number of issuances and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. For example, the second phase of MSHA’s respirable coal mine dust rule went into effect in February 2016 and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air. Additionally, MSHA’s proposed rule, Lowering Miners’ Exposure to Respirable Crystalline Silica and Improving Respiratory Protection, was published in the federal register on July 13, 2023. In April 2024, MSHA issued its final rule, Lowering Miners’ Exposure to Respirable Crystalline Silica and Improving Respiratory Protection, to reduce miner exposures to respirable crystalline silica and improve respiratory protection for all airborne hazards. The final rule lowers the permissible exposure limit of respirable crystalline silica at 50 micrograms per cubic meter of air (μg/m3) for a full shift exposure, calculated as an 8-hour time weighted average, for all miners. The final rule also includes other requirements to protect miner health and update existing respiratory protection requirements. For coal mine operators, the deadline for compliance with the new rule was April 14, 2025. However, on April 11, 2025, the U.S. Court of Appeals for the Eighth Circuit issued an order staying the rule’s compliance deadlines until the court completes a substantive review of the petition. Accordingly, MSHA will continue to temporarily pause enforcement of the requirements in the final rule for mine operators until the litigation is concluded. MSHA also announced in a November 26, 2025 status report in that litigation that it intends to engage in limited rulemaking to reconsider and seek comments on portions of the rule. Our compliance with these or any other new health and safety regulations could increase our mining costs substantially. Further, if we were ever found to be in violation of these regulations, we could face penalties or restrictions that may materially and adversely affect our operations, financial results and liquidity. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Effective October 1, 2022, the trust fund is funded by an excise tax on coal sold of $1.10 per ton for deep-mined coal and $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. For the years ended December 31, 2025 and 2024, we recorded $3.6 million and $3.8 million, respectively, of expense related to this excise tax.

The Patient Protection and Affordable Care Act (“PPACA”) introduced significant changes to the federal black lung program, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, and established a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. On January 18, 2023, the U.S. Department of Labor (“DOL”) announced a notice of proposed rulemaking by its Office of Workers’ Compensation Programs to revise regulations governing the standards related to self-insurance by coal mine operators. The proposed rule would update the standards coal operators must meet to self-insure, modernize and streamline the application process and fix the amount of security applicants must post. The proposed rule would also clarify acceptable forms of security and establish an appeals process. The final rule was published in the Federal Register on December 12, 2024 and became effective on January 13, 2025. We continue to evaluate the final rule, the potential for legal challenges to the final rule and the rule’s potential effects upon us.

Unlike many companies in the coal business, we do not have any liability under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of substantial sums to provide lifetime health benefits to union-represented miners (and their dependents) who retired before 1992, because liabilities under the Coal Act that had been imposed on Alpha Natural Resources, Inc. were settled in the bankruptcy process.

Item 1A. Risk Factors

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. As detailed in the following pages, these risks include, but are not limited to, the following:

•Risks relating to our industry and the global economy, such as those associated with low coal prices, loss of customers, tariffs and other trade restrictions, our ability to obtain financing and other services, competition, decreased demand for coal, customer creditworthiness and global economic disruptions.

•Risks relating to regulatory and legal developments, such as those associated with regulatory requirements and costs, healthcare regulations and costs, permit approvals, climate change regulations, social and governance initiatives and regulations, environmental laws and treaties, unfavorable tax actions, decreased demand for energy, environmental cleanup costs and maintenance of internal controls.

•Risks relating to our operations, such as those associated with mining and other conditions, many of which are beyond our control, disruptions in transportation services, the availability of skilled workers, higher than estimated employee benefit costs, the availability of coal reserves, equipment availability, equipment breakdown, higher than anticipated property reclamation or mine closure costs, unionization, cybersecurity, artificial intelligence, the complexity of mining in Central Appalachia, our dependence upon third parties and our ability to make capital investments.

•Risks relating to our liquidity, such as our ability to obtain or renew surety bonds, our need to maintain capacity for required letters of credit (“LCs”), limitations imposed on us by our borrowing arrangements or any future debt instruments and access to funds when needed.

•Risks relating to the ownership of our common stock, such as those associated with compliance with securities laws, the availability of an orderly trading market for our common stock, our ability to repurchase common shares, as the Board may determine from time to time, dilution or other effects resulting from the issuance of additional securities, impediments to our acquisition by a third party and limited fora for stockholder litigation matters.

These risks, and others, are reviewed in greater detail below. The realization of any of these risks could cause an investment in our securities to decline and result in a loss. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Our results of operations depend substantially upon the prices we receive for our coal. Those prices depend upon factors beyond our control (some of which are described in more detail in other risk factors below), including but not limited to:

•the demand for domestic and foreign coal and coke, which depends significantly on the demand for steel;

•the price and availability of natural gas, other alternative fuels and alternative steel production technologies;

•domestic and foreign economic conditions, including economic downturns and the strength of the global and U.S. economies;

•the consumption pattern of industrial customers;

•factors affecting the timely delivery of our products to customers;

•the proximity to and availability, reliability and cost of transportation and port facilities;

•the legal, regulatory and tax environment for our industry and those of our customers;

•the quantity, quality and pricing of coal available in the resale market;

•the effects of emissions control measures;

•adverse weather, climatic or other natural conditions, natural disasters, epidemics, pandemics and other public health challenges; and

•competition from other suppliers of coal and other energy sources.

A period of sustained low coal prices in the U.S. and other countries would materially adversely affect our operating results and cash flows, as well as the value of our coal reserves, and would cause a number of other risks that we face to increase in likelihood, magnitude and duration.

Alpha produces coal that is sold directly to both U.S. and foreign customers and indirectly to foreign customers through U.S.-based companies. For the year ended December 31, 2025, coal export revenues accounted for approximately 73% of our coal revenues.

For the year ended December 31, 2025, met coal accounted for 96% of our coal revenues. Any deterioration in conditions in the U.S. or foreign steel industries, including the demand for steel and the continued financial viability of the industry, could reduce the demand for our met coal and could impact the collectability of our accounts receivable from U.S. or foreign steel industry customers.

The demand for foreign-produced steel both in foreign markets and in the U.S. market also depends substantially on other factors such as tariff rates on steel. For example, in March 2025, President Trump implemented tariffs, in addition to any existing special rates, on steel and aluminum pursuant to Section 232 of the Trade Expansion Act of 1962. These tariffs may lead to generally higher rates of steel production in the U.S. and therefore greater domestic demand for met coal. However, Alpha’s export customers include foreign steel producers who may be markedly affected by these and similar tariffs to the extent their imports into the U.S. are curtailed as a result of tariffs. Retaliatory tariffs by foreign nations have already limited international trade and may adversely impact global economic conditions. Additional or augmented tariffs proposed and enacted under the Trump administration could in turn provoke additional retaliatory tariffs.

Further, as noted by the Federal Reserve’s April 2025 Beige Book, “uncertainty around international trade policy was pervasive” in early 2025, and in many sectors, because of “on-again, off-again tariffs,” companies delayed capital expenditures and expressed concern regarding increasing inflationary pressures and the health of the U.S. and world economies generally. The November 2025 Beige Book noted that, while tariff uncertainty had decreased from earlier in the year, it “remained a headwind.” Alpha’s ability to plan for future economic conditions is similarly limited by unpredictably evolving trade policies, and this limitation could negatively affect our future operating results.

In addition, the steel industry’s demand for met coal is affected by a number of factors, including the variable nature of that industry’s business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The North American steel industry increasingly relies on processes to make steel that do not use coke, such as electric arc furnaces or pulverized coal processes. As this trend continues, the amount of met coal that we sell and the prices that we receive for it in North America could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. Lower demand for met coal in international markets for any reason would reduce the amount of met coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. Foreign government policies related to coal production and consumption could also negatively impact pricing and demand for our products.

Certain financial institutions, including banks and insurance companies, have adopted policies that prevent or limit those institutions from providing financing, insurance, bonding, and other services to entities that produce, generate power from or use fossil fuels. These policies, and others that may be adopted in the future, may limit our ability to obtain financing, insurance, surety bonds, and other services and may have similar effects upon our customers, which may in turn reduce future global demand for coal. Further, some investors and investment advisors support divestiture of securities issued by companies, such as us, involved in the fossil fuel extraction market. These developments may negatively affect the market for our securities, our access to capital and financial markets and our ability to obtain insurance in the future, which may in turn have significant negative effects on our business, financial condition and results of operations.

Coal sales to our largest customer during the year ended December 31, 2025 accounted for approximately 14% of our total revenues, and coal sales to our 10 largest customers accounted for approximately 77% of our total revenues. These customers could decide to discontinue purchasing coal from us in the volumes that they have previously purchased or decide not to purchase coal from us at all. If several of these customers were concurrently and significantly to reduce their purchases of coal, or if we were unable to sell coal to them on sufficiently favorable terms, we could face a significant reduction in sales while we attempt to sell the coal to other customers in the global marketplace. If such a concurrent loss of large customers or a significant reduction in our sales volume to customers were to happen, our revenues and profitability could be materially and adversely affected.

We compete with numerous other coal producers in various regions of the U.S. for domestic and international sales. We also compete in international markets against coal producers in other countries. International demand for U.S. coal exports also affects coal demand in the U.S. This competition affects domestic and international coal prices and our ability to retain or attract coal customers. The threat of increased production from competing mines and natural gas price declines with large basis differentials have all historically contributed, and may in the future contribute, to lower coal prices.

In the past, high demand for coal and attractive pricing brought new investors to the coal industry, leading to the development of new mines and added production capacity. Subsequent overcapacity in the industry contributed, and may in the future contribute, to lower coal prices.

Potential changes to international trade agreements, trade concessions, foreign currency fluctuations or other political and economic arrangements may benefit coal producers operating in countries other than the United States. Additionally, North American steel producers face competition from foreign steel producers, which could adversely impact the financial condition and business of our customers. We cannot provide assurance that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable foreign trade policies or other arrangements.

Coal is priced internationally in U.S. dollars, and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to offer lower prices for coal to 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. Refer to “Item 1. Business—Competition.” Similarly, currency fluctuations could adversely affect demand for U.S. steel.

Downturns and disruptions in the global economy and financial markets have from time to time resulted in, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others. Significant economic disruptions can result from numerous unpredictable factors, including but not limited to market forces, natural disasters, pandemics, trade disputes and armed conflicts. For example:

•The Chinese government has from time to time implemented regulations and promulgated new laws, policies or restrictions on its domestic coal and steel industries, sometimes with little advance notice, which may affect worldwide coal demand, supply and prices.

•During the COVID-19 pandemic, global supply chain disruptions, including COVID-19-related factory closures and port congestion reduced our ability to obtain some materials used in our operations, reduced the demand for steel, and therefore for met coal, and affected railroad and other transportation systems.

•Although we do not have assets in the Middle East, we do have customers in the region, and if the scope of the ongoing conflicts in that region were to expand materially, the international transport of some goods could become more difficult, even to certain areas outside the Middle East, and shipping costs could increase substantially.

Future disruptions of this sort, and in particular the tightening of credit in financial markets or any other disruption that negatively affects global economic growth, could adversely affect our customers’ ability to obtain financing for operations and result in a decrease in demand, lower coal prices, the cancellation of some orders for our coal and the restructuring of agreements with some of our customers.

Changes in the value of the U.S. dollar relative to other currencies, particularly where imported products are required for the mining process, could result in materially increased operating expenses. Any prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for and price of coal, on our sales, margins and profitability, and on our own ability to obtain financing.

We are unable to predict the timing, duration and severity of any potential future disruptions in financial markets and potential future adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.

The ongoing war between Russia and Ukraine has resulted in substantial sanctions upon Russia and certain supply and market disruptions, particularly in energy markets. Many governments have banned imports from Russia, including commodities such as oil, natural gas and coal. These events have caused volatility in commodity markets. Although we have not experienced any distinct material adverse effect on our results of operations, financial condition or cash flows as a result of the war or the resulting volatility as of the date of this report, such volatility, including market expectations of potential changes in coal prices and inflationary pressures on steel products, may significantly affect prices for our coal or the cost of supplies and equipment, as well as the prices of competing sources of energy for our customers, like natural gas.

This conflict may cause additional materially adverse effects in the region and for international markets. Resulting disruptions could reduce demand for steel made through the use of metallurgical coal and coal-fired electricity, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations, financial condition and cash flows.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness and financial health of our customers. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. In recent years, downturns in the economy and disruptions in the global financial markets have, from time to time, affected the creditworthiness of our customers and limited their liquidity and credit availability. In addition, purchasers of our met coal may increasingly be required to implement costly new emissions and other technologies, thereby increasing the risk we bear for customer payment default.

For the year ended December 31, 2025 we derived 73% of our coal revenues from coal sales made to customers outside the U.S. Our customers in other countries may be subject to other pressures and uncertainties that may also affect their ability to pay, including trade barriers, exchange controls and local economic conditions, threat of military action, and political conditions.

Federal and state regulatory agencies have the authority following significant health and safety incidents, such as fatalities, to order a facility to be temporarily or permanently closed. If this were to occur, we may be required to incur capital expenditures to re-open the facility. In the event that these agencies order the closing of our facilities, our coal sales agreements and our take-or-pay contracts related to our export terminals may permit us to issue force majeure notices, which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the facilities and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery, or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.

Our operations use certain hazardous materials, and, from time to time, we generate limited quantities of hazardous wastes. We may be subject to claims under federal or state law for toxic torts, natural resource damages and other damages as well as for the investigation and clean-up of soil, surface water, sediments, groundwater and other natural resources. Such claims may arise out of current or former conditions at sites that we own or operate, or formerly owned or operated, and at contaminated sites owned or operated by third parties to which we sent wastes for treatment, storage or disposal. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

We operate and maintain a number of coal slurry impoundments. These impoundments are subject to extensive regulation. Some slurry impoundments maintained by other coal mining operations have failed, causing extensive damage to the environment and natural resources, as well as liability for related personal injuries and property damages. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of resulting damages. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties, and potential third-party claims for personal injury, property damage or other losses. In addition, we may become subject to such claims related to surface expressions of methane gas, which can result from underground coal mining activities.

These and other environmental impacts that our operations may have, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could render continued operations at certain mines economically unfeasible or impractical or otherwise materially and adversely affect our financial condition and results of operations.

Our operations are subject to a wide variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations relating to matters such as:

•blasting;

•controls on emissions and discharges;

•the effects of operations on surface water and groundwater quality and availability;

•the storage, treatment and disposal of wastes and the authorizations necessary to create new waste management facilities;

•the remediation of contaminated soil, surface water and groundwater;

•surface subsidence from underground mining;

•the classification of plant and animal species near our mines as endangered or threatened species;

•the reclamation of mined sites; and

•employee health and safety, and benefits for current and former employees (described in more detail below).

These laws and regulations are becoming increasingly stringent. For example:

•federal and state agencies and citizen groups have increasingly focused on the amount of selenium and other constituents in mine-related water discharges;

•The U.S. Mine Safety and Health Administration (“MSHA”) and the states of Virginia and West Virginia have implemented and proposed changes to mine safety and health requirements to impose more stringent health and safety controls, enhance mine inspection and enforcement practices, increase sanctions, and expand monitoring and reporting; and

•Greenhouse gas (“GHG”) emissions reductions are being considered that could increase our costs, require additional controls, or compel us to limit our current operations.

In addition, these laws and regulations require us to obtain numerous governmental permits and comply with the requirements of those permits, which are described in more detail below.

We incur substantial costs to comply with the laws, regulations and permits that apply to our mining and other operations and to address the outcome of inspections. The required compliance and actions to address inspection outcomes are often time consuming and costly and may delay commencement or continuation of exploration or production. In addition, due in part to the extensive and comprehensive regulatory requirements, violations of laws, regulations and permits occur at our operations from time to time and may result in significant costs to us to correct the violations, as well as substantial civil or criminal penalties and limitations or shutdowns of our operations.

Refer to “Item 1. Business—Environmental and Other Regulatory Matters—Clean Water Act—Wastewater Discharge.”

MSHA and state regulators may also order the temporary or permanent closing of a mine in the event of certain violations of safety rules, accidents or imminent dangers. In addition, regulators may order changes to mine plans or operations due to their interpretation or application of existing or new laws or regulations. Any required changes to mine plans or operations may result in temporary idling of production or addition of costs.

These factors have had and will continue to have a significant effect on our costs of production and competitive position and, as a result, on our results of operations, cash flows and financial condition. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may have a similar or more significant impact on us, including delays, interruptions or a termination of operations.

Increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote ESG-related change at public companies, including, but not limited to, through the investment and voting practices of investment advisers, pension funds, universities and other members of the investing community. These activities have also aimed to increase the attention on and demand for action related to various ESG matters, which has contributed to increasing societal, investor, and legislative focus and pressure on ESG practices and disclosures, including those related to climate change, GHG emissions targets, business resilience under the assumptions of demand-constrained scenarios, net-zero ambitions, transition plans, actions related to diversity and inclusion, political activities, minority equity audits, and governance standards. As a result, we may face increasing pressure regarding our ESG practices and disclosures, which could in turn result in the cancellation or delay of projects, the revocation or delay of permits, termination of contracts, lawsuits, regulatory action, and policy change that may adversely affect our business strategy, increase our costs, and adversely affect our reputation and financial performance.

These developments could result in the implementation of certain ESG practices and/or disclosure requirements that present heightened legal, regulatory and reputational risks for us, and complying with these requirements may be costly and time-consuming.

Global climate issues continue to attract considerable public and scientific attention. Numerous reports have expressed concern about the impacts of human activity, and in particular the emissions of GHG, such as carbon dioxide and methane, on global climate issues. Combustion of fossil fuels like coal results in the creation of carbon dioxide, which is emitted into the atmosphere by coal end users such as coal-fired electric power generators, coke plants and steelmaking plants, and, to a lesser extent, by the combustion of fossil fuels by the mining equipment we use. In addition, coal mining can release methane from the mine, directly into the atmosphere. Concerns associated with global climate change, and GHG emissions reduction initiatives designed to address them, have resulted, and are expected to continue to result, in materially increased operating costs for steel producers who use met coal, particularly in Europe.

Emissions from coal consumption and production are subject to pending and proposed regulations as part of regulatory initiatives to address global climate change and global warming. Various international, federal, regional, foreign and state proposals are currently in place or being considered to limit emissions of GHGs, including possible future U.S. treaty commitments, new federal or state legislation, and regulation under existing environmental laws by the EPA and other regulatory agencies and litigation by private parties. These include:

•the 2015 Paris climate summit agreement, which resulted in voluntary commitments by 197 countries to reduce their GHG emissions and could result in additional firm commitments by various nations and states with respect to future GHG emissions. On January 20, 2025, President Trump signed an executive order requiring the U.S. Ambassador to the United Nations to submit formal written notification of the United States’ withdrawal from the Paris Agreement;

•the EPA’s regulations to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South U.S. to states in the Northeast;

•proposed EPA regulations to increase the stringency of the National Ambient Air Quality Standards for particulate matter emissions;

•the EPA's February 2024 regulations increasing the stringency of the National Ambient Air Quality Standards for the primary (health-based) annual standard for PM2.5;

•state and regional climate change initiatives implementing renewable portfolio standards or cap-and-trade schemes;

•challenges to or denials of permits for new coal-fired power plants or retrofits to existing plants by state regulators and environmental organizations due to concerns related to GHG emissions from the new or existing plants;

•private litigation against coal companies or power plant operators based on GHG-related concerns;

•the Glasgow Climate Pact resulting from the 2021 United Nations Climate Change Conference (COP26) held from October 31 to November 13, 2021, which, though not legally binding, contains a plan to reduce use of coal by 40%; and

•the agreement of the participating countries at the 2023 COP28 conference to call on governments worldwide to speed up the transition away from fossil fuels to renewables such as wind and solar power.

On August 3, 2015, the EPA released a final rule establishing the Power Plant NSPS. The final rule requires that newly constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb CO2/MWh-gross. The standard is based on the performance of a supercritical pulverized coal boiler implementing partial CCS. Modified and reconstructed fossil fuel fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance.

In addition, on July 8, 2019, the EPA published the ACE Rule, a replacement of the CPP. In contrast to the CPP, which called for the shifting of electricity generation away from coal-fired sources towards natural gas and renewables, the ACE Rule focuses on reducing GHG emissions from existing coal-fired plants by requiring states to mandate the implementation of a range of technologies at power plants designed to improve their heat rate (i.e., decrease the amount of fuel necessary to generate the same amount of electricity). However, on January 19, 2021, the Court of Appeals of the District of Columbia struck down the ACE rule. The EPA has since announced an intent to consider new regulations governing carbon emissions from existing power plants. In May 2024, the EPA issued a final rule known as the GHG Power Plant Rule that requires stringent reductions in carbon dioxide emissions from existing coal-fired plants and relies heavily on the use of CCS. Numerous petitions for review of the final rule were filed in the U.S. Court of Appeals for the D.C. Circuit and remain pending. More stringent standards for carbon dioxide pollution as a result of these rulemakings could further reduce demand for coal, and our business would be adversely impacted. In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely impact the future global demand for coal.

Furthermore, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption and consumer and corporate preferences for non-coal fuel sources, could cause coal prices and sales of our coal to materially decline and could cause our costs to increase.

Any future laws, regulations or other policies or initiatives of the nature described above may adversely impact our business in material ways. The degree to which any particular law, regulation or policy impacts us will depend on several factors, including the substantive terms involved, the relevant time periods for enactment and any related transition periods. Considerable uncertainty is associated with these regulatory initiatives and legal developments, as the content of proposed legislation and regulation is not yet fully determined and many of the new regulatory initiatives remain subject to governmental and judicial review. In particular, President Biden’s administration has expressed support for the regulation of GHG emissions. In prior Congressional sessions, legislative proposals regulating GHG emissions (such as the Green New Deal) have been introduced, and Congressional leadership may introduce similar legislation this Congressional term. We routinely attempt to evaluate the potential impact on us of any proposed laws, regulations or policies, which requires that we make certain material assumptions. From time to time, we may determine that the impact of one or more such laws, regulations or policies, if adopted and ultimately implemented as proposed, may result in materially adverse impacts on our operations, financial condition or cash flow; however, we often are not able to reasonably quantify such impacts.

In general, any laws, regulations or other policies aimed at reducing GHG emissions have imposed, and are likely to continue to impose, significant costs on many coal-fired power plants, steel-making plants and industrial boilers, which may make them unprofitable. Accordingly, some existing power generators have switched to other fuels that generate fewer emissions and others are likely to switch, some power plants have closed and others are likely to close, and fewer new coal-fired plants are being constructed, all of which reduce demand for coal and the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

Our customers’ operations are subject to extensive laws and regulations relating to environmental matters, including air emissions, wastewater discharges and the storage, treatment and disposal of wastes and operational permits. In particular, the Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from fossil fuel fired power plants, which are the largest end-users of our thermal coal. A series of more stringent requirements have become effective in recent years or will or may become effective in coming years, including:

•implementation of the current and more stringent proposed ambient air quality standards for sulfur dioxide, nitrogen oxides, particulate matter and ozone, including the EPA’s issuance of NAAQS in October 2015 of a more stringent ambient air quality standard for ozone and the EPA’s determinations of attainment designations with respect to these rules;

•implementation of the EPA’s February 2024 revised primary (health-based) annual standard for PM2.5, from 12.0 µg/m3 to 9.0 µg/m3;

•implementation of the EPA’s Revised CSAPR to significantly reduce nitrogen oxide and sulfur dioxide emissions from power plants in 12 states in the eastern United States;

•continued implementation of the EPA’s MATS, which impose stringent limits on emissions of mercury and other toxic air pollutants from electric power generators, issued in December 2011 and in effect pending completion of judicial review proceedings;

•multiple and inconsistent future GHG emission reporting obligations imposed in federal and state laws;

•the exposure of workers to silica dust;

•implementation of the EPA’s August 2014 final rule on cooling water intake structures for power plants;

•more stringent EPA requirements governing management and disposal of coal ash pursuant to a rule finalized in December 2014 and new amendments effective as of August 2018;

•implementation of the COE/EPA final rule revising and reissuing nationwide permits under Section 404 of the Clean Water Act and applying the conforming rule Revised Definition of Waters of the United States; and

•implementation of the EPA’s November 2015 final rule setting effluent discharge limits on the levels of metals that can be discharged from power plants.

These environmental laws and regulations impose significant costs on our customers, which are increasing as these requirements become more stringent. These costs make coal more expensive to use and make it a less attractive fuel source of energy for our customers. Accordingly, some existing power generators have switched to other fuels that generate fewer emissions and others are likely to switch, some power plants have closed and others are likely to close, and no coal-fired plants are currently being constructed in the U.S., all of which reduce demand for coal, the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

In addition, regulations regarding sulfur dioxide emissions under the Clean Air Act, including caps on emissions and the price of emissions allowances, have a potentially significant impact on the demand for our coal based on its sulfur content. We sell both higher sulfur and low sulfur coal. More widespread installation by power generators of technology that reduces sulfur emissions may make high sulfur coal more competitive with our low sulfur coal. Decreases in the price of emissions allowances could have a similar effect. Significant increases in the price of emissions allowances could reduce the competitiveness of higher sulfur coal compared to low sulfur coal and possibly natural gas at power plants not equipped to reduce sulfur dioxide emissions. Any of these consequences could result in a decrease in revenues from some of our operations, which could adversely affect our business and results of operations.

Mining companies must obtain numerous regulatory permits that impose strict conditions on various environmental and safety matters in connection with coal mining. The permitting rules are complex and change over time, potentially in ways that may make our ability to comply with the applicable requirements more difficult or impractical or even preclude the continuation of ongoing operations or the development of future mining operations. Further, regulatory agencies responsible for the review and approval of these permits may not do so in a timely fashion due to lack of resources or other factors. The public, including special interest groups and individuals, have certain rights under various statutes to comment upon, submit objections to and otherwise engage in the permitting process, including bringing citizens’ lawsuits or administrative actions to challenge permits or mining activities.

In the states where we operate, applicable laws and regulations also provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls or is under common ownership or control with us or is determined to be linked to us under OSM’s AVS, have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including being an officer or director of an entity or owning between 10% and 50% of the mining operator. This presumption, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which the relevant coal mining operation is conducted. Thus, past or ongoing violations of federal and state mining laws by us or by coal mining operations owned or controlled by our significant stockholders, directors or officers or by entities linked to us through OSM’s AVS could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. This is known as being “permit-blocked.” In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

As a result, the permitting process is costly and time-consuming, required permits may not be issued or renewed in a timely fashion (or at all), and permits that are issued may be conditioned in a manner that may restrict our ability to conduct our mining activities efficiently. In some circumstances, regulators could seek to revoke permits previously issued. We are required under certain permits to provide data on the impact on the environment of proposed exploration for or production of coal to governmental authorities.

In particular, certain of our activities require a dredge and fill permit from the COE under Section 404 of the CWA. In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements and a series of court challenges, which have resulted in increased costs and delays in the permitting process.

Additionally, we may rely on nationwide permits under the CWA Section 404 program for some of our operations. These nationwide permits are issued every five years, and the 2021 nationwide permit program was reissued in 2021. If we are unable to use the nationwide permits and require an individual permit for certain work, that could delay operations.

Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. For example, many of our permits governing surface stream and groundwater discharges and impacts will be subject to new and more stringent conditions to address various new water quality requirements upon renewal over the next several years. Although we have no estimates at this time, our costs to satisfy these conditions could be substantial.

Future changes or challenges to the permitting and mine plan modification and approval process could cause additional increases in the costs, time, and difficulty associated with obtaining and complying with the permits and could delay or prevent commencing or continuing exploration or production operations and, as a result, adversely affect our coal production, cash flows and profitability.

Recent actions by the EPA, including the EPA’s February 2024 revision of the primary (health-based) annual standard for PM2.5, from 12.0 µg/m3 to 9.0 µg/m3, the proposed rule for more stringent emission standards for particulate matter emissions, and the proposed MATS rule to regulate emissions of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal- and oil-fired power plants, referred to as “MATS,” may make it more difficult for our customers to continue to use our coal in their operations.

Proposed SEC GHG reporting rules have been stayed by federal courts and, under the Trump administration, the SEC has determined not to defend the rules in court, but there can be no assurances that federal climate rules will not be enforced. California’s enactment of its own GHG reporting laws in October 2023 also suggests the possibility of inconsistent and/or duplicative future GHG reporting requirements, which would likely add to our operating costs.

We are responsible for maintaining systems and documentation necessary to evaluate the effectiveness of our internal control over financial reporting. These activities may divert management’s attention from other business concerns. To maintain and improve our controls and procedures, we must commit significant resources, may be required to hire additional staff and need to continue to provide effective management oversight, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

From time to time, legislation is proposed that could result in the reduction or elimination of certain U.S. federal income tax provisions currently available to companies engaged in the exploration, development, and production of coal reserves. These proposals have included, but are not limited to: (1) the elimination of current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) the repeal of the percentage depletion allowance with respect to coal properties and (3) the repeal of capital gains treatment of coal and lignite royalties. The passage of these or other similar proposals could increase our taxable income and negatively impact our cash flows and the value of an investment in our common stock.

Changes in tax laws, in the areas of both income taxes and non-income taxes, may materially affect our results of operations and could cause our financial position and profitability to deteriorate.

We pay non-income taxes on the coal we produce. A substantial portion of our non-income taxes are levied as a percentage of gross revenues, while others are levied on a per ton basis. If such liabilities were to arise, or if non-income tax rates were to increase significantly, our results of operations could be materially and adversely affected.

Further, changes in tax laws may materially affect our results of operations and could cause our financial position and profitability to deteriorate. On August 16, 2022, legislation commonly referred to as the Inflation Reduction Act of 2022 (“IRA”) was signed into law. Among other provisions, the IRA enacted a 15% corporate alternative minimum tax and a 1% excise tax on repurchases of corporate stock for tax years beginning after December 31, 2022. We have accrued a stock repurchase excise tax of $327 related to the share repurchase program as of December 31, 2025, which is recorded in treasury stock at cost.

Our income is taxable in the U.S., with a significant portion historically qualifying for preferential treatment as foreign-derived deduction eligible income (“FDDEI”) deduction, formerly foreign-derived intangible income (“FDII”). If U.S. tax rates increase or the FDDEI deduction is eliminated or reduced our future provision for income taxes, results of operations, net income, and cash flows could be adversely affected. Also, if our customers move manufacturing operations to the U.S., our future FDDEI deduction may be reduced.

On July 4, 2025, legislation commonly referred to as the “One Big Beautiful Bill Act” (“OBBBA”) was signed into law. Changes made by the OBBBA include the reinstatement of 100% bonus depreciation, the reinstatement of immediate expensing for domestic research and experimentation costs, changes to the calculation of FDDEI and the interest expense limitation, and the addition of metallurgical coal to the list of “applicable critical minerals” for purposes of the Section 45X credit. The Section 45X credit (also known as the advanced manufacturing production credit), as amended, provides a refundable tax credit equal to 2.5% of the production costs for metallurgical coal produced during tax years 2026 through 2029. We incorporated the effects of the OBBBA in our income tax provision for the year ended December 31, 2025, and noted no material impacts to our estimated annual effective tax rate.

Our coal production at our mines is subject to operating conditions and events, many of which are beyond our control, that could disrupt operations, affect production and the cost of mining for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we have experienced in the past and/or may experience in the future include:

•changes or variations in geologic, hydrologic or other conditions, such as the thickness of the coal deposits and the amount of rock, clay or other non-coal material embedded in or overlying the coal deposit;

•mining, processing and loading equipment failures and unexpected maintenance problems;

•limited availability or increased costs of mining, processing and loading equipment and parts and other materials from suppliers;

•difficulties associated with mining under or around surface obstacles;

•unfavorable conditions with respect to proximity to and availability, reliability and cost of transportation facilities;

•adverse weather and natural disasters, such as heavy snows, heavy rains and flooding, lightning strikes, hurricanes or earthquakes;

•accidental mine water discharges, coal slurry releases and failures of an impoundment or refuse area, including inadvertent environmental impacts to the local community;

•mine safety accidents, including fires and explosions from methane and other sources;

•hazards or occurrences that could result in personal injury and loss of life;

•a shortage of skilled and unskilled labor;

•security breaches, cyber attacks or terroristic acts;

•strikes and other labor-related interruptions;

•delays or difficulties in, the unavailability of, or unexpected increases in the cost of acquiring, developing or permitting new acquisitions from the federal government and other new mining reserves and surface rights;

•competition and/or conflicts with other natural resource extraction activities and production within our operating areas;

•the termination of material contracts by state or other governmental authorities; and

•fatalities, personal injuries or property damage arising from train derailments, mined material or overburden leaving permit boundaries, underground mine blowouts, impoundment failures, subsidence or other unexpected incidents.

If any of these or other conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining, delay or halt production or sales to our customers, result in regulatory action or lead to customers initiating claims against us. Any of these consequences could adversely affect our operating results or result in impairments to our assets.

In addition, our mining operations are concentrated in a small number of material mines. As a result, the effects of any of these conditions or events may be exacerbated and may have a disproportionate impact on our results of operations and assets.

We maintain insurance policies that provide limited coverage for some, but not all, of these risks. Even where covered by insurance, these risks may not be fully covered, and insurers may contest their obligations to make payments. Failures by insurers to make payments could have a material adverse effect on our cash flows, results of operations or financial condition.

For the year ended December 31, 2025, 89% of our coal volume was transported from our shipping points to a vessel loading point or customer location by rail. Deterioration in the reliability of the service provided by rail carriers because of, for example, insufficient allocation of resources to us by rail companies or a strike by railroad workers, could result in increased internal coal handling costs and decreased shipping volumes. If we were unable to find alternatives, our business would be adversely affected, possibly materially. Most of our operations are serviced by a single rail carrier. Due to the difficulty in arranging alternative transportation, these operations are particularly at risk of disruptions, capacity issues or other difficulties with that carrier’s transportation services, which could adversely and materially affect our revenues and results of operations.

Further, we depend significantly upon the reliable operation of the DTA coal export terminal in Newport News, Virginia. DTA, in which we hold a 65.0% ownership interest, provides us with the ability to fulfill a broad range of customer coal quality requirements through coal blending, while also providing storage capacity and transportation flexibility. Any significant disruption in DTA’s functions and operations or other limitations upon the capacity of DTA or other transportation facilities could adversely and materially affect our revenues and results of operations.

We also depend upon trucks, barges and ocean vessels to deliver coal to our customers. In addition, much of our coal is transported from our mines to our loading facilities by trucks owned and operated by third parties. Disruption of any of these transportation services due to weather-related problems, mechanical difficulties, fuel and supply costs, strikes, lockouts, bottlenecks, accidents, terrorist attacks or other events could impair our ability to supply coal to our customers, resulting in decreased shipments and revenue. Disruption in shipment levels over long periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and results of operations.

An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production on a profit-making basis and could therefore adversely affect our revenues and earnings. Because transportation costs represent a significant portion of the total cost of coal for our customers, increases in transportation costs could also reduce overall demand for coal or make our coal production less competitive than coal produced from other sources or other regions.

We are responsible for certain liabilities under a variety of benefit plans and other arrangements with employees. The unfunded status of these obligations as of December 31, 2025 included $49.6 million of workers’ compensation obligations, net of expected insurance receivable amounts, $87.3 million of pension obligations and $130.6 million of black lung obligations. These obligations have been estimated based on assumptions including actuarial estimates, discount rates, and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us. In addition, the DOL has a legislative directive to periodically review operators’ financial standing and federal black lung liabilities, which could result in a substantial increase in required security, negatively impacting liquidity. The DOL recently issued new regulations which substantially increase the collateral required to secure self-insured federal black lung obligations. The new rules require 100% minimum collateral for black lung obligations. If the final rules are not modified or stayed through legal action, we estimate we would be required to provide approximately $80.0 million to $100.0 million of collateral to secure certain of our black lung obligations. The 2025 Final Regulation permits us to use combinations of letters of credit, surety bonds, and cash to meet the collateral requirement.

Our business plan and strategy require substantial capital expenditures. We require capital for, among other purposes, acquisition of surface rights, equipment and the development of our mining operations, capital renovations, maintenance and expansions of plants and equipment and compliance with safety, health and environmental laws and regulations. Future debt or equity financing may not be available on satisfactory terms or at all or, if available, may result in dilution. If we are unable to obtain additional capital, we may not be able to maintain or increase our existing production rates, and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.

Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers, supervisors and other staff. We, along with the mining industry generally, are currently facing a significant shortage of operating staff. Moreover, we are seeing an increasing number of those who leave our employment accept new positions outside the coal industry, further reducing the number of skilled employees available to us and leading to increased labor costs. When coal producers compete for skilled miners, recruiting becomes more difficult, and employee turnover rates typically increase, each of which negatively affect operating efficiency and costs. If we are unable to train or retain the necessary number of staff, it could adversely affect our productivity, costs and ability to maintain or expand production.

In addition, we depend on the experience and industry knowledge of our officers and other key employees to design and execute our business plans. If we experience a substantial turnover in our leadership and other key employees, and those persons are not replaced by individuals with comparable skills, our performance could be materially adversely impacted. Furthermore, we may be unable to attract and retain additional qualified executives as needed in the future. We believe that our future success will depend on our continued ability to attract and retain highly skilled and qualified personnel. There is a high level of competition for experienced, successful personnel in our industry. Our inability to meet our executive staffing requirements in the future could impair our growth and harm our business.

We contract with third parties to operate certain of our mines. Under those arrangements, we retain certain contractual rights of oversight over these mines, which are operated under our permits or leases, but we do not control, and our employees do not participate in, the day-to-day operations of these mines. Operational difficulties at these mines, increased competition for contract miners from other coal producers and other factors beyond our control could affect the availability, cost and quality of coal produced for us by contractors. Disruption in our supply of contractor-produced coal could impair our ability to fill our customers’ orders or require us to pay higher prices to obtain the required coal from other sources. Any increase in the per-ton compensation for services we pay for the production of contractor-produced coal could increase our costs and, therefore, lower our earnings and adversely affect our results of operations. We also contract with third parties to perform reclamation services for properties that are no longer in operation. If these third parties fail to meet their obligations under those contracts or are otherwise ineffective, it could increase our costs and, therefore, lower our earnings and adversely affect our results of operations.

Our business, or the businesses of our customers and suppliers, may be impacted by disruptions such as terrorist or cybersecurity attacks or failures, threats to physical security, and extreme weather conditions or other natural disasters. These disruptions or any significant increases in energy prices that follow could result in government-imposed price controls. Our insurance, or the insurance of third-party service providers, may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of met coal reserves, as well as other activities related to our businesses. We own and operate some of these systems and applications while others are owned and operated by our third-party service providers. In the ordinary course of business, we and our service providers collect, process, transmit and store data, such as proprietary business information and personally identifiable information.

Our IT systems and those of third parties, including third-party service providers, are vulnerable to malicious and intentional cyberattacks involving ransomware, malware and viruses, accidental or inadvertent incidents, the exploitation of security vulnerabilities or “bugs” in software or hardware, among other scenarios. Both the frequency and magnitude of cyberattacks are expected to increase, and attackers are becoming more sophisticated, particularly given the increasing availability and sophistication of “artificial intelligence” systems. Further, security vulnerabilities may be introduced from the use of artificial intelligence by us, our customers or third parties. The development of quantum computing technology, if successful, may also eventually pose very significant encryption and other data security risks. Geopolitical tensions or conflicts, such as Russia’s invasion of Ukraine, conflicts in the Middle East or increased tension with China, may also create a heightened risk of cybersecurity attacks.

A cyber attack may involve persons gaining unauthorized access to our digital systems for purposes of gathering, monitoring, releasing, misappropriating or corrupting proprietary or confidential information, or causing operational disruption. Unauthorized physical access to one of our facilities or electronic access to our information systems could result in, among other things, unfavorable publicity and reputational harm, litigation by affected parties, damage to sources of competitive advantage, disruptions to our operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to remediate such security vulnerabilities, any of which could have a substantial impact on our results of operations, financial condition or cash flows. Additionally, we may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.

Strategic targets, such as energy-related assets, may be at greater risk of future cybersecurity attacks than other targets in the U.S. Our defensive preparedness against cybersecurity attacks includes limited technological capabilities for prevention and detection of cybersecurity disruptions; internal governance processes that assist to identify, protect, and remediate security risks routinely; non-technological measures such as threat information sharing with industry groups; internal training and awareness campaigns including testing of employee awareness and an emphasis on resiliency. If the measures we and our cloud service providers are taking to protect against cybersecurity disruptions prove to be insufficient or if our proprietary data is otherwise not protected, we as well as our customers, employees, or third parties could be adversely affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation or reputational harm. Further, as cybersecurity attacks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cybersecurity attacks.

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Our estimated total reclamation and mine-closing liabilities were $227.4 million as of December 31, 2025, based upon permit requirements, the historical experience at our operations and a number of variables involving assumptions and estimates. Total reclamation and mine-closing liabilities are, therefore, subject to change due to a variety of factors, including estimates of future asset retirement costs and the timing of these costs, estimates of proven reserves, assumptions involving profit margins of third-party contractors, inflation rates and discount rates. Our future operating results and financial position could be materially adversely affected by these factors. In addition, significant changes from period to period could result in significant variability in our operating results, which could reduce comparability between periods and impact our liquidity. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” for a description of our estimated costs of these liabilities.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires, steel, magnetite and other raw materials and consumables, which in some cases, do not have ready substitutes. Some equipment and materials are needed to comply with regulations, such as proximity detection devices on continuous mining machines. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies.

Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows. Diesel fuel is one of our largest variable costs and a sustained shortage of diesel fuel could negatively and materially impact our results of operations.

In addition, the prices we pay for materials are strongly influenced by the global commodities markets. Coal mines consume large quantities of these commodities, such as steel, copper, rubber products, explosives and diesel and other liquid fuels. A rapid or significant increase in the cost of these commodities would increase our mining costs. Further, if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially adversely impact our profitability.

The U.S. and global economies recently experienced high levels of inflation. If inflation were to return to higher levels for an extended period, a related increase in our input costs could materially adversely affect our profitability.

We purchase coal from third parties, for use in coal blending and for other purposes, for which ready substitutes may not be immediately available. The failure of these third parties to provide coal in a timely fashion or a significant reduction in availability or an increase in the cost of these supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

We are able to mine, process and market some of our coal reserves as either met coal or high-quality thermal coal. In deciding our approach to these reserves, we assess the conditions in the met and thermal coal markets, including factors such as the current and anticipated future market prices of met coal and thermal coal, the generally higher price of met coal as compared to thermal coal, the lower volume of saleable tons that results when producing coal for sale in the met market rather than the thermal market, the increased costs of producing met coal, the likelihood of being able to secure a longer term sales commitment for thermal coal and our contractual commitments to deliver different types of coal to our customers. A decline in demand for met coal relative to thermal coal could cause us to shift coal from the met market to the thermal market, thereby reducing our revenues and profitability.

Our profitability depends substantially on our ability to mine in a cost-effective manner coal reserves of the quality our customers need. Although we have coal reserves that we believe could support current production levels for approximately a decade, estimating the size and quality of reserves requires significant judgment and could prove to be inaccurate. We may not be able to mine all of our reserves as profitably as we do at our current operations. Under adverse market conditions, some reserves could not be mined profitably at all. In addition, in order to develop our reserves, we must receive various governmental permits. As discussed above, some of these permits are becoming increasingly more difficult and expensive to obtain, and the review process continues to lengthen. We may be unable to obtain the necessary permits on terms that would allow us to operate profitably or at all.

Because our reserves are depleted as we mine our coal, our future success and growth depend in part on our ability to timely acquire additional coal reserves that are economically recoverable. Our planned development projects and acquisition activities may not result in significant additional reserves, and we may not succeed in developing new mines or expanding existing mines beyond our existing reserves. Replacement reserves may not be available when required or, if available, may not be able to be mined at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we now own or subsequently acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results due to lost production capacity from diminished or discontinued operations at those mines, as well as lay-offs, write-off charges and other costs, potentially causing an adverse effect that is disproportionate to the percentage of overall production represented by those mines. Our ability to acquire other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates available on commercially reasonable terms, among other factors. If we are unable to replace or increase our coal reserves on acceptable terms, our production and revenues will decline as our reserves are depleted.

After we acquire coal reserves, we are required to obtain a permit to mine the reserves through the applicable state agencies prior to mining the acquired coal. In part, permitting requirements provide that, under certain circumstances, we must obtain surface owner consent if the surface estate has been severed from the mineral estate, which is commonly known as a “severed estate.” At certain of our mines where we have obtained the underlying coal and the surface is held by one or more third-party owners, we are engaged in negotiations for surface rights with multiple parties. If we are unable to successfully negotiate surface rights with any or all of these surface owners, or to do so on commercially reasonable terms, we may be denied a permit to mine some or all of our coal or may find that we cannot mine the coal at a profit. If we are denied a permit, that would create significant delays in our mining operations and materially and adversely impact our business and results of operations. Furthermore, if we decide to alter our plans to mine around the affected areas, we could incur significant additional costs to do so, which could increase our operating expenses considerably and could materially and adversely affect our results of operations.

Our operations at times face potential conflicts with holders of other mineral interests such as coalbed methane, natural gas and oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal reserves and active operations, potentially creating conflicting interests between us and the holders of those interests. From time to time we acquire these minerals ourselves to prevent conflicting interests from arising. If, however, conflicting interests arise and we do not acquire the competing mineral rights, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. Furthermore, the rights of third parties for competing uses of adjacent, overlying or underlying lands, such as oil and gas activity, coalbed methane, pipelines, roads, easements and public facilities, may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated. If we are unable to reach an agreement with the holders of such rights, or to do so on a cost-effective basis, we may incur increased costs, and our ability to mine could be impaired, which could materially and adversely affect our business and results of operations.

The geological characteristics of Central Appalachian coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available or, if available, may not be able to be mined at costs comparable to those of the depleting or depleted mines. In addition, compared to mines in other areas of the country, permitting, licensing and other environmental and regulatory requirements in Central Appalachia are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines in Central Appalachia.

Our estimates of economically recoverable coal reserves and coal resources are based on engineering, economic and geological data and assumptions. Our estimates as to the quantity and quality of the coal in our reserves depend upon a variety of factors and estimates, many of which involve uncertainties and factors beyond our control and may vary considerably from actual results, such as:

•geological and mining conditions that may not be fully identified by available exploration data or that may differ from experience in current operations;

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

•the assumed ability to obtain future permits and effects of regulation and taxes by governmental agencies; and

•assumptions about coal prices, operating costs, mining technology improvements, development costs and reclamation costs.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular property, classifications of reserves and coal resources based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. In addition, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves and resources may vary materially from estimates. Accordingly, our estimates may not accurately reflect our actual reserves and resources. Any inaccuracy in our reserve estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.

We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and, in some cases, title is not verified at all. Accordingly, actual or alleged defects in title or boundaries may exist, which may result in the loss of our right to mine on the property or in unanticipated costs to obtain leases or mining contracts to allow us to conduct our mining operations on the property, which could adversely affect our business and profitability. Furthermore, some leases require us to produce a minimum quantity of coal and/or pay minimum production royalties. If those requirements are not met, the leasehold interest may terminate.

We have in the past, and may in the future, undertake strategic transactions such as the acquisition or disposition of coal mining and related infrastructure assets, interests in coal mining companies, joint ventures or other strategic transactions involving companies with coal mining or other energy assets. Our ability to complete these transactions is subject to the availability of attractive opportunities, including potential acquisition targets that can be successfully integrated into our existing business and provide us with complementary capabilities, products or services on terms acceptable to us, as well as general market conditions, among other things.

Risks inherent in these strategic transactions include, but are not limited to:

•accurately assessing the geological conditions of acquired properties;

•the ability to obtain and maintain surety bonds, at acceptable rates, related to acquired properties and other obligations;

•uncertainties in assessing the value, strengths, and potential profitability, and identifying the extent of all weaknesses, risks, contingent liabilities and other liabilities of acquisition candidates and strategic partners;

•the potential loss of key customers, management and employees of an acquired business;

•the ability to achieve identified operating and financial synergies from an acquisition or other strategic transactions in the amounts and on the time frame due to inaccurate assumptions underlying estimates of expected cost savings, the deterioration of general industry and business conditions, unanticipated legal, insurance and financial compliance costs, or other factors;

•the ability of management to manage successfully our exposure to pending and potential litigation and regulatory obligations;

•the ability of a purchaser to complete the transfer of operating permits related to our divested operations and to otherwise properly fulfill all assumed contractual, legal and regulatory obligations;

•unanticipated increases in competition that limit our ability to expand our business or capitalize on expected business opportunities, including retaining current customers; and

•unanticipated changes in business, industry, market, or general economic conditions that differ from the assumptions underlying our rationale for pursuing the acquisition or other strategic transactions.

The ultimate success of any strategic transaction we may undertake will depend in part on our ability to continue to realize the anticipated synergies, business opportunities and growth prospects from those transactions. We may not be able to successfully integrate the companies, businesses or properties that we acquire, invest in or partner with. Problems that could arise from the integration of an acquired business may involve:

•coordinating management and personnel and managing different corporate cultures;

•applying our safety and environmental programs at acquired mines and facilities;

•establishing, testing and maintaining effective internal control processes and systems of financial reporting for the acquired business;

•the diversion of our management’s and our finance and accounting staff’s resources and time commitments, and the disruption of either our or the acquired company’s ongoing businesses;

•tax costs or inefficiencies; and

•inconsistencies in standards, information technology systems, procedures or policies.

Any one or more of these factors could cause us not to realize the benefits anticipated from a strategic transaction, adversely affect our ability to maintain relationships with clients, employees or other third parties or reduce our earnings.

Moreover, any strategic transaction we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. Future transactions could also result in our assuming more long-term liabilities relative to the value of the acquired assets. Further, acquisition accounting rules require changes in certain assumptions made subsequent to the measurement period, as defined in current accounting standards, to be recorded in current period earnings, which could affect our results of operations.

Approximately 97% of our total workforce and approximately 96% of our hourly workforce was union-free as of December 31, 2025. However, under the National Labor Relations Act, employees have the right at any time to form or affiliate with a union. Any further unionization of our employees or the employees of third-party contractors who mine coal for us could adversely affect the stability of our production and reduce our profitability.

Our union-represented employees could strike, which would disrupt our production, increase our costs and disrupt shipments of coal to our customers, and could result in the closure of affected mines, all of which could reduce our profitability.

Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as BTUs, sulfur content, ash content, grindability, moisture and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Further, some of our coal supply agreements allow our customers to terminate the contract in the event of regulatory changes that restrict the type of coal the customer may use at its facilities or the use of that coal or increase the price of coal or the cost of using coal beyond specified limits. In addition, our coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during specified events beyond the control of the affected party.

As a result of these issues, we may not achieve the revenue or profit we expect to achieve from our coal supply agreements.

On October 27, 2023, we entered into a new Credit Agreement (the “ABL Agreement”) which was amended and extended on May 6, 2025. The ABL Agreement includes an asset-based revolving credit facility (the “ABL Facility”), which among other things, provides for the issuance of LCs.

Obligations secured by LCs may increase in the future, for example due to increased collateral obligations associated with black lung obligations. If we do not maintain sufficient borrowing capacity under our letter of credit facilities, we may be unable to provide financial assurance for self-insured obligations which could negatively impact our ability to fund future working capital, capital expenditure or other general corporate requirements.

A significant source of liquidity is our cash balance. Access to additional funds from liquidity-generating transactions or other sources of external financing may not be available to us and, if available, would be subject to market conditions and certain limitations, including our credit rating and covenant restrictions in our ABL Facility.

Under the ABL Facility, we may borrow cash or obtain LCs, on a revolving basis, in an aggregate amount of up to $225.0 million. We may request an increase to the capacity of the facility of up to $75.0 million provided that $25.0 million may be solely for the purpose of providing additional availability to obtain cash collateralized LCs. Availability under the ABL Facility is calculated monthly and fluctuates based on qualifying amounts of coal inventory, trade accounts receivable and in certain circumstances specified amounts of cash. We must maintain minimum Liquidity, as defined in the ABL Agreement, of $75.0 million. The ABL Facility matures on May 4, 2029.

The terms of the ABL Facility impose operating and financial restrictions on us and our subsidiaries, which may limit our ability to respond to changing business and economic conditions. For example, we are limited in our ability to incur additional indebtedness, make particular types of investments, incur certain types of liens, engage in fundamental corporate changes, enter into transactions with affiliates, make substantial asset sales, make certain restricted payments, enter into amendments or waivers to certain agreements, conduct certain sale leasebacks or enter into certain burdensome agreements. These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions. We regularly evaluate opportunities to enhance our capital structure and financial flexibility through a variety of methods, including repayment or repurchase of outstanding debt, amendment of our credit facility and other facilities, and other methods. As a result of any of these actions, the restrictions and covenants that apply to us may become more restrictive or otherwise change.

Any failure to comply with those covenants may constitute a breach under the ABL Facility that could result in the acceleration of all or a substantial portion of any outstanding indebtedness and termination of revolving credit commitments under the ABL Facility. As of December 31, 2025, we are in compliance with the operating and financial covenants under the ABL Facility. Our inability in the future to maintain our ABL Facility could materially adversely affect our liquidity and our business.

Operating results below current levels, or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our covenants and payment obligations contained in our borrowing arrangements. If we violate these covenants or obligations under any of these agreements and are unable to obtain waivers from our lenders, our debt under all of these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us.

If our debt is in default for any reason, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs (including related to black lung), coal leases and other obligations. These bonds are typically renewable annually. Under applicable regulations, self-bonding may not be available to us as a means to comply with our reclamation bonding obligations for the foreseeable future. Surety bond issuers and holders may not continue to renew the bonds, may demand less favorable terms upon renewal or may impose new or increased collateral requirements. As of December 31, 2025, we had outstanding surety bonds with third parties of $170.0 million, with $147.6 million related to active reclamation projects. Surety bond issuers and holders may demand additional collateral, unfavorable terms or higher fees. Our failure to retain, or inability to acquire, surety bonds or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and results of operations. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds, restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place, or our inability to comply with our reclamation bonding obligations through self-bonding. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, depending on the amount of any cash collateral required, could have a material adverse impact on our liquidity and financial position. If we are unable to meet cash collateral requirements and cannot otherwise obtain or retain required surety bonds, we may be unable to satisfy legal requirements necessary to conduct our mining operations.

Difficulty in acquiring surety bonds, or additional collateral requirements, would increase our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our liquidity. If we are unable to provide the financial assurance that is required by state and federal law to secure our reclamation and coal lease obligations, our ability to mine or lease coal and, as a result, our results of operations could be materially and adversely affected.

At December 31, 2025, we had $13.4 million of indebtedness outstanding, of which $9.2 million is scheduled to mature in the next three years.

Our indebtedness could have important consequences to our business, particularly if the amount of our indebtedness should materially increase in the future. For example, indebtedness could:

•make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any related decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments;

•force us to seek additional capital, restructure or refinance our debts, or sell assets;

•cause us to be less able to take advantage of significant business opportunities such as acquisition opportunities and to react to changes in market or industry conditions;

•cause us to use a portion of our cash flow from operations for debt service, reducing the availability of working capital and delaying or preventing investments, capital expenditures, research and development and other business activities;

•cause us to be more vulnerable to general adverse economic and industry conditions;

•expose us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest;

•expose us to the risk of foreclosure on substantially all of our assets and those of most of our subsidiaries, which secure certain of our indebtedness if we default on payment or are unable to comply with covenants or restrictions in any of the agreements;

•limit our ability to borrow additional monies in the future to fund working capital, capital expenditures and other general corporate purposes; and

•result in a downgrade in the credit ratings of our indebtedness, which could harm our ability to incur additional indebtedness and result in more restrictive borrowing terms, including increased borrowing costs and more restrictive covenants, all of which could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

We may incur additional secured or unsecured indebtedness in the future, subject to compliance with covenants in any existing debt agreements. Our ability to meet future debt service obligations will depend on our future cash flow from operations and our ability to restructure or refinance our debt, which will depend on the condition of the capital markets and our financial condition at that time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations, and the terms of existing or future debt instruments may restrict us from adopting some of these alternatives.

As a public company with securities listed on the New York Stock Exchange (“NYSE”), we must comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements occupies a significant amount of time for our Board of Directors (the “Board”) and management and requires us to incur significant costs. We are required to:

•maintain a comprehensive compliance function;

•comply with rules promulgated by the NYSE;

•prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

•maintain internal controls and policies; and

•engage outside counsel and accountants in the above activities.

We are responsible for assessing the operating effectiveness of internal controls over financial reporting and we may conclude that our internal controls over financial reporting are ineffective. Additionally, our independent registered public accounting firm may issue an adverse report indicating that our internal controls are not effective due to deficiencies in how our controls are documented, designed, operated or reviewed. Efforts to remediate any such deficiencies and otherwise comply with these requirements may strain our resources, and we may be unable to do so in a timely or cost-effective manner.

The total authorization to repurchase our stock under the existing common share repurchase program adopted by our Board of Directors on March 4, 2022 is $1.5 billion. As of December 31, 2025, $361.3 million of the originally authorized amount remained available for additional repurchases. This share repurchase program does not obligate us to repurchase any dollar amount or number of shares of our common stock and may be suspended or discontinued at any time, which could cause the market price of our common stock to decline.

Repurchases pursuant to our share repurchase program could affect the price of our common stock and increase its volatility. Important factors that could cause us to limit, suspend or delay our share repurchases, without prior notice, and that could in any event impact our management’s exercise of our discretion as to the amount and timing of such repurchases, include market conditions, the trading price of the stock, applicable legal requirements, compliance with the provisions of our debt agreements, and other factors. The existence of our share repurchase program could cause the price of our common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for our common stock. Additionally, repurchases under our share repurchase program would diminish our cash reserves, which could adversely affect our operating results. There can be no assurance that any share repurchases would enhance stockholder value because the market price of our common stock may decline below the levels at which we repurchased such shares. Any failure to repurchase shares could negatively impact our reputation, investor confidence in us and our stock price.

Although we have done so in the past, we do not currently pay dividends on our common stock. Dividends on our common stock may be paid only if declared by the Board. The Board is not legally obligated or required to declare dividends on our common stock even if we have funds available for that purpose.

In addition, even if the Board wishes to declare a dividend, we cannot make payments of cash in respect of dividends to the extent such payments are not permitted under Delaware law.

Alpha’s common stock trades on the NYSE under the ticker symbol “AMR.” Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. An active, liquid and orderly trading market for our common stock may not be maintained, however. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, shareholders could lose a substantial part or all of their investment in our common stock.

The following factors, among others, could affect our stock price:

•our operating and financial performance, including reserve estimates;

•an unexpected mine or environmental incident;

•quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

•the public reaction to our press releases, our other public announcements and our filings with the SEC;

•strategic actions by our competitors;

•changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•speculation in the press or investment community;

•research analysts’ coverage of our common stock, or their failure to cover our common stock;

•sales of our common stock by us, our directors or officers or the selling stockholders or the perception that such sales may occur;

•our payment of dividends;

•changes in accounting principles, policies, guidance, interpretations or standards;

•additions or departures of key management personnel;

•actions by our stockholders;

•general market conditions, including fluctuations in commodity prices;

•public sentiment regarding climate change and fossil fuels;

•domestic and international economic, legal and regulatory factors unrelated to our performance; and

•the realization of any of the other risks described under this “Risk Factors” section or described elsewhere in this document.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. One factor fueling this volatility has been information available in public media published by third parties, including blogs, articles, message boards and social and other media, that may include statements not attributable to the company under discussion and may not be reliable or accurate. Broad market fluctuations or inaccurate and unreliable information about our company may adversely affect the trading price of our common stock.

We may issue additional shares of common stock or convertible securities in subsequent public offerings or, for example, in connection with an acquisition. We cannot predict the size or timing of future issuances, if any, or the effect that any future issuances and sales may have on the market price of our common stock.

Our certificate of incorporation, as amended, authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events, or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock, as the Board may determine.

Provisions contained in our certificate of incorporation and bylaws, as amended, could impose impediments to the ability of a third party to acquire us even if a change of control would be beneficial to our stockholders. These documents contain provisions imposing various procedural and other requirements which could make it more difficult for stockholders to effect certain corporate actions. For example, our certificate of incorporation authorizes the Board to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, the Board can authorize the issuance of shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These provisions may have the effect of delaying or deterring a change of control of our company and could limit the price that certain investors might be willing to pay in the future for shares of our common stock.

A change of control (as defined under the instruments governing our debt from time to time) could be an event of default, permitting our lenders to accelerate the maturity of certain borrowings. Further, our borrowing arrangements currently, and may in the future, impose other restrictions on us, including with respect to mergers or consolidations with other companies and the sale of substantially all of our assets. These provisions could prevent or deter a third-party from acquiring us even where the acquisition could be beneficial to our stockholders.

Our bylaws provide, subject to limited exceptions, that the Court of Chancery of the State of Delaware is, to the fullest extent permitted by law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders; (iii) any action asserting a claim against us, any director or our officers or employees arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation (including any certificate of designations relating to any class or series of preferred stock) or our bylaws; or (iv) any action asserting a claim against us, any director or our officers or employees that is governed by the internal affairs doctrine. This provision does not apply to suits brought to enforce a duty or liability under the Exchange Act or any other claim for which the U.S. federal courts have exclusive jurisdiction. In addition, our bylaws provide that the federal district courts of the United States of America will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock shall be deemed to have notice of and to have consented to the provisions of our bylaws described above. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, other employees or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision that is contained in our bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of met coal reserves, as well as other activities related to our businesses. We own and operate some of these systems and applications while others are owned and operated by third-party service providers.

We maintain a cybersecurity program employing many components and strategies to mitigate and remediate day-to-day cybersecurity threats and exposures. This program, along with a robust information technology internal controls framework, helps to ensure the confidentiality, integrity and availability of our information systems. The program includes elements for identifying, assessing and managing material risks from cybersecurity threats. Our incident response and change management policies and procedures were designed based on guidelines from the National Institute of Standards and Technology Cybersecurity Framework.

We take a risk-based approach to cybersecurity, which begins with the identification and evaluation of cybersecurity risks or threats that could affect our operations, finances, legal or regulatory compliance, or reputation. We employ continuous monitoring systems and other technologies and security controls to assist us with the identification of cybersecurity risks and threats. At least annually we conduct a third-party risk assessment to identify cybersecurity risks associated with third-party vendors and service providers. When cybersecurity risks are identified, we prioritize mitigation strategies based upon risks’ potential impact, likelihood, velocity and vulnerability, considering both quantitative and qualitative factors. These strategies include, among others, the application, adoption or modification of cybersecurity policies and procedures, implementation of administrative, technical and physical controls and employee training, education and awareness initiatives.

Our cybersecurity risk management includes continuous monitoring of networks and systems for potential signs of suspicious activity. Our Information Systems and Technology Department (the “IT Department”) monitors security alerts or indicators and initiates triage, verification and remediation actions when needed. We also provide mechanisms and training for employees to report to the IT Department any unusual or potentially malicious activity they observe for proper identification and analysis.

In the event of a significant cybersecurity incident, we establish an incident response team that works in conjunction with the IT Department to identify, contain, eradicate and, if necessary, recover from a cybersecurity incident. Through third parties we are also able to rapidly deploy forensic analysis, legal services, notification and call center services and credit and identity monitoring if required.

We track key performance indicators and cybersecurity metrics to evaluate the efficacy of our cybersecurity controls and practices. Further, our cybersecurity program is periodically reviewed by senior members of management and adjusted as needed in an effort to maintain the program’s agility and responsiveness as circumstances and technologies evolve, new cybersecurity threats emerge and regulations change.

In addition, we operate an enterprise risk management (“ERM”) program to identify, evaluate and manage risks. Cybersecurity risks are evaluated alongside other critical business risks under the ERM program to align cybersecurity efforts with our broader business goals and objectives. We believe that integrating cybersecurity risks into our ERM program fosters a proactive and holistic approach to cybersecurity, which helps safeguard our operations, financial condition and reputation in an ever-evolving threat landscape. Cybersecurity risks are further considered and evaluated as part of an annual risk assessment performed independently by our internal audit department.

We maintain an incident response policy and program focused upon detecting, managing, documenting and reporting incidents affecting our systems and data, including those specific to cybersecurity. In the event of a significant cybersecurity incident, we appoint a dedicated incident team, including a team leader, responsible for managing and coordinating incident response efforts. These efforts may include detecting, identifying, defending against, responding to and, if necessary, recovering from cybersecurity incidents. Incidents that meet certain thresholds are escalated to senior members of management, internal legal advisors, communication specialists and other key stakeholders for additional guidance and action.

Cybersecurity Service Providers and Third-Party Consultants. At least annually we engage independent cybersecurity consultants, auditors and other third parties to assess and enhance our cybersecurity risk assessment and practices. These third parties conduct independent assessments, penetration testing and vulnerability assessments to identify weaknesses and recommend improvements. Additionally, we employ a number of third-party tools and technologies as part of our efforts to enhance cybersecurity functions and monitoring.

Oversight of Third-Party Service Providers. We use third-party service providers to support our operations and many of our technology initiatives, including third parties that house financial or sensitive information.

Our technology acquisition policy and our internal controls framework require us to obtain and review attestation reports regarding these third-party service providers and their sub-service processors or providers and their internal controls, complementary user entity controls and contractual obligations, including those specific to cybersecurity. We evaluate cybersecurity risks associated with our use of third-party service providers, which may include a review of a service provider’s cybersecurity posture or a recommendation of specific mitigation controls. We determine and prioritize service provider risk based on potential threat impact and likelihood and these risk determinations determine the level of due diligence and ongoing compliance monitoring required for each service provider.

As of the date of this report, we have not identified any cybersecurity threats that have materially affected or are reasonably anticipated to have a material effect on the organization. Although we have not previously experienced cybersecurity incidents that are individually, or in the aggregate, material, we have experienced cyberattacks in the past, which we believe have thus far been deflected or mitigated by our preventative, detective and responsive measures. For additional discussion of our cybersecurity related risks, refer to “Item 1.A Risk Factors.”

The Board is responsible for overseeing management’s assessments of major risks facing us and for reviewing options to mitigate these risks. The Board’s oversight of cybersecurity risks occurs at both the Board level and through its Audit Committee.

The Board. The Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer, other members of senior management and other personnel and advisors, as requested by the Board, report on our financial, operating and commercial strategies, as well as major related risks, which may include cybersecurity risks, at regularly scheduled meetings of the Board. The Board may request follow-up data and presentations to address any specific concerns or recommendations.

The Audit Committee. The Audit Committee reviews with our management team, including our Senior Vice President – Information Systems and Technology, our cybersecurity frameworks, policies, technologies, programs, opportunities, strategies and risks. These presentations highlight any significant cybersecurity incidents, the cyber threat landscape, cybersecurity program enhancements, cybersecurity risks, related remediation and mitigation activities, security user awareness and reporting training program and any other relevant cybersecurity topics. In addition, members of our Legal Department advise the Audit Committee as needed regarding cybersecurity-related legal matters, including disclosure requirements. Management believes that these reports help to provide the Audit Committee with an informed understanding of our cybersecurity program, risks and strategies. The Audit Committee may request follow-up data and presentations to address any specific concerns or recommendations. In addition to this periodic reporting, significant cybersecurity risks or threats may also be escalated to the Audit Committee as needed based upon our cyber incident reporting process. The Audit Committee reports regularly to the entire Board and reviews with the Board any major issues that arise at the committee level, which may include cybersecurity risks.

Our IT Department addresses current and emerging cybersecurity matters. This function is led by our Senior Vice President – Information Systems and Technology, who reports to our Chief Financial Officer. The IT Department’s security team, a cross-functional group composed of members who all have 7 to 27 years of professional and technical information technology experience, oversees the cybersecurity program to help ensure the confidentiality, integrity and availability of our systems and mitigate day-to-day threats and exposures. It is responsible for measuring and managing cybersecurity risk, including the prevention, detection, mitigation and remediation of cybersecurity incidents and also for implementing cybersecurity policies, programs, procedures and strategies. The security team reports significant cybersecurity incidents to senior management, internal legal advisors, communication specialists and other key stakeholders as required.

Item 2. Properties

Refer to “Item 1. Business” for information on our active mining properties.

Our corporate headquarters consists of approximately 50,000 square feet of leased office space at 340 Martin Luther King Jr. Boulevard in Bristol, Tennessee.

As of December 31, 2025, we estimate that we owned or controlled approximately 294.5 million tons of marketable proven and probable bituminous coal reserves and approximately 522.6 million tons of in situ bituminous coal resources. Our coal reserve and resource estimates were prepared by Marshall Miller & Associates, Inc. (“Marshall Miller”), an independent professional mine engineering and geological consulting firm. Technical Summary Reports prepared by Marshall Miller, as a qualified person, for each of our material mining properties are filed as exhibits to this Annual Report on Form 10-K and incorporated herein by reference.

Coal reserve and resource estimates are based on data obtained from drilling activities and other available geologic data. Estimating reserves and resources requires the use of geologic, engineering, and economic assumptions. Our engineering and land personnel work closely with Marshall Miller to ensure the integrity and accuracy of the data used to calculate the estimates as well as to ensure the assumptions used are reasonable based on our historical results as well as current and future anticipated mine plans. We provide Marshall Miller with historical property information including property maps, deed, lease, and permit information, drilling and lab results, mine plans, production quantities, development, capital, and operating costs as well as market information. For our active and certain idled Met mining properties, Marshall Miller performs an initial assessment and based on the level of geological evidence estimates our coal resources and classifies such resources as either inferred, indicated or measured. When we consider it cost beneficial, Marshall Miller further conducts a pre-feasibility study to estimate our coal reserves and classify such reserves as either proven or probable. The estimates and reports prepared by Marshall Miller are reviewed by our personnel to ensure such reports have been prepared in accordance with applicable rules and regulations and that estimates are based on reasonable assumptions and reflect known facts and circumstances updated through year-end.

Economic analysis is a required part of the process of estimating coal reserves and resources. For a coal reserve or resource to be considered economic, generally revenue generated from its sale must exceed its total cost of production (including consideration of development, capital, and operating costs).

In determining coal reserves as of December 31, 2025, the following estimated market pricing was utilized:

(1) Market pricing shown on U.S. East Coast basis.

(2) Met and thermal pricing based on 10-year and 3-year average, respectively, of forecasted pricing from pricing services.

The following is a summary of our estimated marketable proven and probable coal reserves as of December 31, 2025 as determined by Marshall Miller:

(1)     Minimum seam height generally 30 inches for underground mines.

(1)     Kingston/Mammoth thermal reserves primarily proven and >1% sulfur; Marfork and McClure/Toms Creek thermal reserves primarily probable and ≤1% sulfur.

(2)     Recovery percentage defined as estimated coal reserves divided by related estimated in situ measured and indicated coal resources.

In performing an initial assessment for purposes of determining coal resources as of December 31, 2025, the following estimated market pricing was utilized:

(1)    Market pricing shown on U.S. East Coast basis.

(2)    Pricing shown for primary product judgmentally selected by qualified person based on review of historical average pricing for each complexes coal products over the past 5 years.

The following is a summary of our estimated in situ inferred, indicated, and measured coal resources (exclusive of coal reserves) as of December 31, 2025 as determined by Marshall Miller:

(1)     Amounts shown exclusive of coal reserves.

(2)     Inferred resources were not considered material and have not been presented.

(1)     Amounts shown exclusive of coal reserves.

(2)     Expected recovery percentage defined as potential estimated recoverable tons divided by estimated in situ measured and indicated coal resources.

Our coal reserves and resources are owned or are controlled through leases with third parties, which have varied expiration dates and either have options to renew or are expected to be renewed until all mineable and merchantable coal is exhausted. Leases require the payment of production royalties to lessors based on a stated percentage of sales revenue less freight cost and may contain annual minimum payment requirements. We permit coal reserves and resources in advance of mining. Currently, there are no known permitting issues that would impact the reporting of our coal reserves or resources. However, also refer to “Item 1. Business—Environmental and Other Regulatory Matters” and “Item 1A. Risks Factors—Risks relating to regulatory and legal developments.”

Our coal reserve and resource estimates are updated periodically to reflect coal production, acquisitions and dispositions of mineral interests, new drilling, mine or geological data, and changes in regulations, market conditions or other economic factors.

As coal seams in the United States have been mined for many years and are well established, we do not conduct material exploration activity. However, we periodically conduct drilling of additional core holes to provide additional geological evidence as part of our routine mine permitting and planning processes. The following is a summary of the changes in our coal reserves and resources for the year ended December 31, 2025: