Alpha Metallurgical Resources, Inc. 10-K

Item 1. Business Unless otherwise indicated or the context otherwise requires, references in this “Item 1. Business” section to “the combined company,” “we,” “us” and other similar terms refer to Alpha Metallurgical Resources, Inc. and its consolidated subsidiaries (previously Contura Energy, Inc. and its consolidated subsidiaries). Disclosures in this “Item 1. Business” section should be read in conjunction with “Item 1A. Risk Factors” for further discussion of factors impacting our business. Effective February 1, 2021, we changed our corporate name from Contura Energy, Inc. to Alpha Metallurgical Resources, Inc. to more accurately reflect our strategic focus on the production of metallurgical coal. Following the effectiveness of our name change, our ticker symbol on the New York Stock Exchange changed from “CTRA” to “AMR” effective on February 4, 2021. Our Company 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 15 underground mines, seven surface mines and nine coal preparation plants. 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 22 and 23 to the Consolidated Financial Statements for geographical information about our coal sales and additional segment information. We have a substantial reserve base of 316.0 million tons of proven and probable reserves as of December 31, 2023. Our reserve base consists of 303.0 million tons of proven and probable metallurgical reserves, and 12.9 million tons of proven and probable thermal reserves. Through our operations across the CAPP coal basin in Virginia and West Virginia, 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. Other Business Developments During 2023, development was completed and production began 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. In August 2023, we completed our transition to a pure-play metallurgical producer with the closure of Slabcamp, which was our last remaining thermal mine. Our History 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. We entered into various settlement agreements with the Debtors, their bankruptcy successor, and third parties as part of the Debtors’ bankruptcy reorganization process. We assumed acquisition-related obligations through those settlement agreements, which became effective on July 26, 2016, the effective date of the Debtors’ Plan of Reorganization. As of December 31, 2023, we did not have any remaining acquisition-related obligations. Refer to Note 14 to the Consolidated Financial Statements for further information on our acquisition-related obligations. On December 8, 2017, we closed a transaction with Blackjewel to sell our Western Mines located in the PRB, Wyoming, along with related coal reserves, equipment, infrastructure and other real properties. On October 4, 2019, we closed on the ESM Transaction in connection with Blackjewel’s subsequent bankruptcy filing. On May 29, 2020, certain of our subsidiaries 7 Table of Contents (Contura Coal West, LLC and Contura Wyoming Land, LLC), one of which held the mining permits for the Western Mines, were merged with certain subsidiaries of ESM to become wholly-owned subsidiaries of ESM and to complete the permit transfer process in connection with the ESM Transaction. 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.” On December 10, 2020, we closed on a transaction with Iron Senergy Holdings, LLC, to sell our thermal coal mining operations located in Pennsylvania consisting primarily of our Cumberland mining complex and related property (our former NAPP operations). This transaction accelerated our strategic exit from thermal coal production to shift our focus to met coal production. Effective February 1, 2021, we changed our corporate name from Contura Energy, Inc. to Alpha Metallurgical Resources, Inc. to more accurately reflect our strategic focus on the production of met coal. Following the effectiveness of our name change, our ticker symbol on the New York Stock Exchange changed from “CTRA” to “AMR” effective on February 4, 2021. Our Mining Operations and Properties The following table provides a summary of information regarding our active mining complexes as of December 31, 2023 (see also “Item 2. Properties” for further information): (Amounts in thousands, except for mine data ) Tons Sold (4) Mining Complex Location Acquired Mines (1) Equipment (2) Rail (3) 2023 2022 2021 Carrying Value (5) Reserves (6) Aracoma WV 2018 3 CM CSX 2,607 2,643 2,221 $ 174,652 41,276 Kepler WV 2018 1 CM CSX/NS 1,958 1,897 1,571 $ 235,203 41,190 Kingston WV 2018 4 CM/S/H CSX 2,254 1,935 2,348 $ 34,208 38,657 Marfork WV 2018 6 CM/S/H CSX 4,345 4,106 4,032 $ 322,733 97,653 McClure/Toms Creek VA 2016 5 CM/S/H CSX/NS 4,071 3,703 4,033 $ 114,530 68,747 Power Mountain WV 2016 2 CM NS 718 832 837 $ 70,594 — Elk Run WV 2018 1 CM CSX — — — $ 35,535 28,434 (1) Number of active mines as of December 31, 2023. (2) Equipment: S = Shovel/Excavator/Loader/Trucks; CM = Continuous Miner; 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, 2023. (6) Proven and probable reserves as of December 31, 2023. 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 5 to 16 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, McDowell, and Raleigh counties, West Virginia. The complex has one active underground mine (with an estimated life of 15 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 – Kingston 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 three active surface mines which produced 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 8 Table of Contents 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. 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 2 to 17 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 two active surface mines 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 2 to 27 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 County, West Virginia. The complex has one active underground mine (with an estimated life of 3 years) which produces High-Vol. B quality met coal from the Eagle coal seam. Coal is processed at the Power Mountain Preparation Plant and loaded onto NS rail for delivery to customers. In addition, during 2023 development was completed and production began at a second underground mine (with an estimated life of 15 years) which produces High-Vol. B quality met coal from the Powellton coal seam. Coal from the mine is currently trucked to and processed through the Mammoth Preparation Plant. Following the expected development of a haul road in 2024, coal is expected to be trucked to and processed through the Power Mountain Preparation Plant. Elk Run – Elk Run is a mining complex located in Boone County, West Virginia. During 2023, development was completed and production began at an underground mine (with an estimated life of 22 years) which produces High-Vol. B quality met coal from the Powellton coal seam. Coal from the mine is processed at the Chess Processing Plant and loaded onto CSX rail for delivery to customers. Equipment 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. Preparation Plants, Loadouts, and Docks The following is a summary of information regarding our active preparation plants as of December 31, 2023 : Preparation Plant Year Constructed/Upgraded Processing Capacity (Tons per hour) Utilization % Power Source Bandmill 2010 1,200 66% American Electric Power Kepler 1967 900 54% American Electric Power Kingston 1974/2001 700 73% American Electric Power Marfork 1994/2019 2,400 70% American Electric Power McClure 1979/2019 1,100 53% American Electric Power Toms Creek 1980/2004 1,100 43% American Electric Power Power Mountain 1985/2010 1,200 26% American Electric Power Chess Processing (1) 1980/1998 2,200 N/A American Electric Power Mammoth 1950/2008 1,200 18% American Electric Power (1) Plant refurbished in 2023. Produced tons received during the fourth quarter of 2023 but not processed until the first quarter of 2024. The following is a summary of information regarding our active loadouts and docks as of December 31, 2023 : 9 Table of Contents Loadout/Dock Year Constructed Loading Capacity (Tons per hour) Pax Loadout 2006 3,500 Feats Loadout 1975 3,500 Marmet Dock 1986 1,600 Export Terminal The following is a summary of information regarding DTA (in which we own a 65% interest) as of December 31, 2023: Export Terminal Year Constructed Loading Capacity (Tons per hour) Storage Capacity (Net tons) DTA 1984 Up to 6,500 1.7 million Coal Mining Techniques 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. Room-and-Pillar Mining Certain of our mines in CAPP 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 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. Truck-and-Shovel Mining and Truck and Front-End Loader Mining We utilize truck/shovel and truck/front-end loader mining methods at some of our CAPP 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 which 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. Contour Mining We use contour mining at certain of our CAPP 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. Highwall Mining We utilize highwall mining methods at certain of our CAPP 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. 10 Table of Contents Financial Information About Reportable Segments and Geographic Areas Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition—Results of Operations” and Notes 22 and 23 to the Consolidated Financial Statements for financial information about our reportable segment and geographic areas. Marketing, Sales and Customer Contracts 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 coals are 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 25 and 26 countries during the years ended December 31, 2023 and 2022, respectively. Asia was our largest export market for the years ended December 31, 2023 and 2022, with coal sales to Asia accounting for approximately 46% and 53%, respectively of export coal revenues and 34% and 43%, respectively, of coal revenues. All of our sales are conducted in U.S. dollars. Refer to Note 22 to the Consolidated Financial Statements for additional export coal revenue information. Met coal accounted for approximately 95% of our coal revenues for each of the years ended December 31, 2023 and 2022. Our met coal sales are typically made with 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 5% of our coal revenues for each of the years ended December 31, 2023 and 2022. We sometimes enter into long-term contracts with our thermal 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, 2023 and 2022, approximately 21% and 54%, respectively, of our thermal coal sales volume were delivered pursuant to long-term contracts. Distribution and Transportation 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 11 Table of Contents 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, 2023 and 2022, 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 84% of total shipments of coal volume from our mines during the years ended December 31, 2023 and 2022, 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. Procurement 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. In the first quarter of 2023, we completed a series of transactions to acquire a number of coal trucks and related equipment and facilities to secure trucking services for our operations. In December 2022, we purchased substantially all of the assets of a mining equipment component manufacturing and rebuild business to help secure the supply of certain underground mining equipment parts needed for our operations. 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. Competition The coal industry is highly competitive, both in the U.S. and internationally. In the met coal market, of the approximately 72.4 million tons produced in the U.S. in 2023, we produced approximately 14.8 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 71% of our met coal tons sold were shipped internationally in 2023. In the thermal market, of the approximately 502.0 million tons produced in the U.S. in 2023, we produced approximately 1.9 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 66% of our thermal coal tons sold were shipped internationally in 2023. 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. 12 Table of Contents Human Capital Resources As of December 31, 2023, we had approximately 4,160 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, 2023. Certain of our subsidiaries have wage agreements with the UMWA representing roughly 3% of our workforce. Certain of our subsidiaries have wage agreements with the UMWA that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2025 and one on February 28, 2026. 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, 2023, we had approximately 3,900 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, 2023, approximately 37% of our total workforce had at least ten years of service with our Company, while approximately 25% had fifteen or more years of service with our Company. Employee Compensation and Benefits 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; retention programs; 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 (“EAP”) 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. Employee Training and Development 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 (“EMT”), Mechanical Engineering Technology (“MET”), 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. Employee Safety, Health, and Welfare 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 13 Table of Contents 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 2023, we achieved an overall Non-fatal days lost (“NFDL”) safety incident rate that was 41% 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 three quarters of 2023 and the Alpha rate reflects full year 2023. 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 2023, Alpha mine rescue teams won two overall grand champion awards along with several other first-place awards in both overall competition honors and technical category titles. Refer to Exhibit 95 Mine Safety Disclosure included in this Annual Report on Form 10-K for additional mine safety information. Legal Proceedings We could become party to legal proceedings from time to time. 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, 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 the Company’s legal proceedings, refer to Note 21 , part (d), to the Consolidated Financial Statements, which is incorporated herein by reference. 14 Table of Contents ENVIRONMENTAL AND OTHER REGULATORY MATTERS 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 require substantial increases in equipment and operating costs to us and delays, interruptions, or a termination of operations, the likelihood or extent of which we cannot predict. In particular, the U.S. Securities and Exchange Commission (“SEC”) continues to work to finalize regulations it proposed in March 2022 intended to standardize climate-related disclosures. 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 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, 2023, we had accrued $205.4 million for reclamation liabilities and mine closures, including $38.9 million of current liabilities. Mining Permits and Approvals 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. On October 4, 2019, the WV Bankruptcy Court entered an order approving the sale by Blackjewel of the Western Assets to ESM. The ESM Transaction occurred on October 18, 2019. We were the former owner of the Western Assets, having sold them to Blackjewel in December 2017 (the “2017 Blackjewel Sale”). As the mine permit transfer process relating to our sale of the Western Assets to Blackjewel had not been completed prior to Blackjewel’s and certain of its affiliates’ filing petitions for relief under chapter 11 of title 11 of the U.S. Code (the “Bankruptcy Code”), we remained the permitholder in good standing for both 15 Table of Contents mines. In connection with ESM’s acquisition of the Western Assets from Blackjewel, on October 18, 2019, we and ESM finalized an agreement that provided, among other items, for the eventual transfer of the Western Asset permits from us to ESM and replacement by ESM of our surety bonds associated with these properties. In furtherance of certain objectives contemplated under that agreement, we and ESM agreed to the merger of two of our now-former subsidiaries, i.e. , Contura Coal West, LLC (“CCW”), which held and still holds the Western Asset permits, and Contura Wyoming Land, LLC (“CWL”), with certain entities formed by ESM for purposes of acquiring CCW and CWL. The ESM entities involved in the mergers were ESM Coal West SPV, LLC (“First Merging Entity”) and ESM Wyoming Land SPV, LLC (“Second Merging Entity”). The mergers were consummated effective May 29, 2020, with the First Merging Entity merging with and into CCW, with CCW as the surviving entity (the “First Surviving Entity”), and the Second Merging Entity merging with and into CWL, with CWL as the surviving entity (the “Second Surviving Entity”). Upon the mergers becoming effective, each of the First Surviving Entity and the Second Surviving Entity became wholly-owned subsidiaries of ESM. As such, the Western Asset permits are still held by the same entity, Contura Coal West, LLC, but said entity is no longer a subsidiary of ours, and we no longer have surety bonds associated with these permits and properties. 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. 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 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 16 Table of Contents 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 each of the years ended December 31, 2023 and 2022, we recorded $2.0 million 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”). Surety Bonds 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, 2023 and 2022, our posted third-party surety bond amount in all states where we operate was approximately $177.1 million and $165.6 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. Clean Air Act 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 particulate matter, sulfur dioxide, nitrogen oxides, 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 or 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, particulate matter, 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, particulate matter and ozone, in each case making the standards more stringent. As a result, some states 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 17 Table of Contents decision to retain the existing National Ambient Air Quality Standards for particulate matter set by the Obama-Biden Administrations without changes. However, on January 6, 2023, the EPA proposed to revise the primary (health-based) annual standard for PM2.5, from its current level of 12.0 parts per billion (ppb or 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 its current level of 12.0 µg/m3 to 9.0 µg/m3. The EPA retained the 24-hour standard and the current primary 24-hour standard for PM10, which provides protection against coarse particles. The EPA is not changing the secondary (welfare-based) standards for fine particles and coarse particles at this time. In October 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 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. On March 15, 2023, the EPA issued its Good Neighbor Plan rules (the “Good Neighbor Plan”), which secure significant reductions in cross-state air pollution of ozone-forming emissions of nitrogen oxides (NOx) from power plants and industrial facilities. The Good Neighbor Plan is intended to reduce seasonal ozone-forming emissions of NOx from power plants and industrial facilities in 23 states. Industry groups and the State of Ohio have filed lawsuits challenging the Good Neighbor Plan. Due to court orders staying implementation of certain aspect of the Good Neighbor Plan, the EPA is implementing the Good Neighbor Plan only in certain states. As of September 21, 2023, the Good Neighbor Plan's “Group 3” ozone-season NOx control program for power plants is being implemented in the following states: Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and Wisconsin. Due to the court orders, the EPA is not currently implementing the Good Neighbor Plan “Group 3” ozone-season NOx control program for power plants in the following states: Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and West Virginia. On December 20, 2023, the United States Supreme Court agreed to hear oral argument in four consolidated cases challenging the Good Neighbor Plan. The Court has scheduled oral argument for the cases in its February 2024 term and directed the parties to address, among other issues, whether the emissions controls imposed by the Good Neighbor Plan are reasonable regardless of the number of states subject to the Good Neighbor Plan. • 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 were delayed due to litigation. In October 2014, 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. 18 Table of Contents 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 is the subject of a pending legal challenge in the D.C. Circuit by five states. 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. For states to meet their requirements under the Final CSAPR Update rule, a number of coal-fired electric generating units will likely need to be retired, rather than retrofitted with the necessary emission control technologies, reducing demand for thermal coal. 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 Standards. The EPA finalized the Revised CSAPR Update rule on April 30, 2021. The EPA estimated that the Revised CSAPR Update rule will 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. • 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 stated that it plans on sending a draft proposal to the White House questioning the EPA’s earlier finding and intends to reevaluate the MATS rule itself. 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 is also establishing emission standards from these facilities. The new subcategory and emission standards will affect six existing EGUs 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 is also taking final action on the residual risk and technology review that is required by the CAA Section 112. The EPA states, “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. 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 19 Table of Contents 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 may result in additional emissions restrictions from new coal-fueled power plants whose operations may impair visibility at and around federally protected areas. This program may also require certain existing coal-fueled power plants 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 result in additional coal plant closures and affect the future market for coal. A final Regional Haze rule was published on January 10, 2017. 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 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 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. In addition, numerous U.S. governors, mayors and businesses have pledged their commitments to the goals of 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 20 Table of Contents 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 is now 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. 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 are currently pending. There is a risk that CCS technology may not be commercially practical in limiting emissions as otherwise required by the rule or similar rules that may be proposed in the future. If such legislative or regulatory programs are adopted or maintained, and economic, commercially available carbon capture technology for power plants is not developed or adopted in a timely manner, it would negatively affect our customers and would further reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to decline, perhaps materially. 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. The EPA has since announced an intent to consider new regulations governing carbon emissions from existing power plants. 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 21 Table of Contents 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 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. The Company currently does 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. Clean Water Act 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: Wastewater Discharge 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 22 Table of Contents 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. On March 5, 2014, the EPA, the U.S. Department of Justice (“DOJ”), West Virginia Department of Environmental Protection, the Pennsylvania Department of Environmental Protection and the Kentucky Energy and Environment Cabinet filed a Complaint against Alpha Natural Resources, Inc. and its permit holding subsidiaries in Kentucky, Pennsylvania, Tennessee, Virginia and West Virginia alleging that Alpha Natural Resources, Inc.’s mining affiliates in those states and in Tennessee and Virginia exceeded certain water discharge permit limits during the period of 2006 to 2013 and simultaneously entered into a Consent Decree with Alpha Natural Resources, Inc. resolving their claims. The Consent Decree was entered by the Southern District of West Virginia on November 26, 2014 and amended on June 12, 2016 and again on February 28, 2018 (the “Alpha Natural Resources, Inc. Consent Decree”). As part of the Alpha Natural Resources, Inc. Consent Decree, Alpha Natural Resources, Inc. agreed to implement an integrated environmental management system and an expanded auditing/reporting protocol, install selenium and osmotic pressure treatment facilities at specific locations, and certain other measures. The Alpha Natural Resources, Inc. Consent Decree required Alpha Natural Resources, Inc. to pay $27.5 million in civil penalties, to be divided among the federal government and state agencies. All required water treatment systems have been constructed, the environmental management system has been implemented, and the other terms and conditions of the Alpha Natural Resources, Inc. Consent Decree have been substantially satisfied. On February 25, 2020, partial termination of the Consent Decree was granted by the EPA for all but 6 of the Alpha Natural Resources, Inc. Defendants. On January 29, 2021, full termination of the Consent Decree was granted for all the Defendants. Dredge and Fill Permits 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 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 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 Nationwide Permits 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. Nationwide Permits 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 Nationwide Permit numbers including 5 and 49) and January 13, 2021 (affecting Nationwide Permit numbers including 21 and 50), the COE published its final rules reissuing and modifying its Nationwide Permits. These Nationwide Permits 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 Nationwide permits. 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 Clean Water Act's (“CWA”) jurisdictional reach over waters of the United States, referred to as the Navigable Waters Protection Rule (“NWPR”). The rule replaces 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 are 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. 23 Table of Contents 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. Its ultimate impact on our operations remains uncertain until the agencies regularly implement and apply the rule. Cooling Water Intake In May 2014, the EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase our customers’ costs and may adversely affect the demand for coal, which may materially impact our results or operations. Effluent Guidelines 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 establishes 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 changes the technology basis for treatment of Flue Gas Desulfurization Wastewater and Bottom Ash Transport Water. Endangered Species Act 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. 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. Resource Conservation and Recovery Act 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 24 Table of Contents 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. 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. Comprehensive Environmental Response, Compensation and Liability Act 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. Other Environmental Laws 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. Federal and State Nuclear Material Regulations 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. Mine Safety and Health 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 25 Table of Contents 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. The U.S. Mine Safety and Health Administration (“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. The proposed rule would set 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 proposal also includes other requirements to protect miner health and update existing respiratory protection requirements. The written comment period on the proposed rule was originally scheduled to end on August 28, 2023, and was later extended to September 11, 2023. MSHA held three public hearings to give stakeholders the opportunity to present testimony, written comments, and other documentary evidence on the proposed rule. The final rule is anticipated to be published in 2024. Our compliance with these or any other new mine health and safety regulations could increase our mining costs. If we were 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 January 1, 2022, the trust fund was funded by an excise tax on coal sold of $0.50 per ton for deep-mined coal and $0.25 per ton for surface-mined coal, neither amount to exceed 2% of the gross sales price. Effective October 1, 2022, the trust fund was 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, 2023 and 2022, we recorded $4.6 million and $2.6 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 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. Comments on the proposed rule were originally due no later than March 20, 2023. The Department of Labor subsequently extended the deadline for comments until April 19, 2023, and has not yet issued a final rule. Coal Industry Retiree Health Benefit Act of 1992 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. 26 Table of Contents GLOSSARY 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. Cumberland Back-to-Back Coal Supply Agreement. Certain agreements with Iron Senergy under which Iron Senergy would sell to the Company all of the coal that the Company was obligated to sell to customers under Cumberland coal supply agreements (“Cumberland CSAs”) which existed as of the transaction closing date but did not transfer to Iron Senergy at closing (each, a “Cumberland Back-to-Back Coal Supply Agreement”). Each Cumberland Back-to-Back Coal Supply Agreement had economic terms identical to, but offsetting, the related Cumberland CSA. If a Cumberland customer subsequently consented to assign a Cumberland CSA to Iron Senergy after closing, the related Cumberland CSA would immediately and automatically transfer to Iron Senergy and the related Cumberland Back-to-Back Coal Supply Agreements executed by the parties would thereupon terminate as set forth therein. Development stage property. A property with disclosed coal reserves but no material extraction. ESG. Environmental, social and governance sustainability criteria. ESM Transaction. The sale by Blackjewel L.L.C. (“Blackjewel”) of the Eagle Butte and Belle Ayr mines located in Wyoming (the “Western Mines” or “Western Assets”) to Eagle Specialty Materials (“ESM”), an affiliate of FM Coal, LLC on October 18, 2019. The ESM Transaction was approved by the United States Bankruptcy Court for the Southern District of West Virginia (the “WV Bankruptcy Court”) pursuant to an order on October 4, 2019. The Company was the former owner of the Western Assets, having sold them to Blackjewel in December 2017. 27 Table of Contents 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 between 31% and 34.5% on a dry basis. High-Vol B. A coking coal used in steel production with a volatile matter content 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 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 between 23% -31% on a dry basis. 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 the MSHA. 28 Table of Contents 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. 29 Table of Contents