Alpha Metallurgical Resources (AMR) 10-K2020 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the transition period from           to

Commission File Number 001-38735

Securities registered or to be registered pursuant to Section 12(g) of the Act:

(Title of Class)

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

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

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

The aggregate market value of the Common Stock held by non-affiliates of the registrant (excluding outstanding shares beneficially owned by directors, executive officers, and other affiliates) on June 30, 2020, was approximately $56 million based on the closing price of the Company’s common stock as reported that date on the New York Stock Exchange of $3.04 per share. Such assumptions should not be deemed to be conclusive for any other purpose. 

Number of shares of the registrant’s Common Stock, $0.01 par value, outstanding as of February 28, 2021: 18,389,139

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2021 annual meeting of stockholders (the “Proxy Statement”), which will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2020.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

Part I

Unless otherwise indicated or the context otherwise requires, references in this “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). 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 across Virginia and West Virginia. With customers across the globe, high-quality reserves and significant port capacity, we are a leading U.S. supplier of metallurgical products for the steel industry. We operate high-quality, cost-competitive coal mines across the Central Appalachia (“CAPP”) coal basin. Our portfolio of mining operations consists of 16 underground mines, seven surface mines and eight coal preparation plants. We own a 65.0% interest in Dominion Terminal Associates (“DTA”), a coal export terminal in eastern 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 low-ash metallurgical (“met”) coal, including High-Vol. A, Mid-Vol., High-Vol. B, and Low-Vol. coal, which is shipped to domestic and international coke and steel producers. Although our strategic focus is on the production of met coal, we also produce low sulfur, high British thermal unit (“BTU”) thermal coal for electricity generation, as well as specialty coal for industrial customers. Our thermal coal is primarily sold to the domestic power generation industry.

We have two reportable segments: Met, and CAPP - Thermal. Refer to Note 25 to the Consolidated financial statements for more information about our reportable segments.

We have a substantial reserve base of 445.0 million tons of proven reserves and approximately 178.5 million tons of probable reserves, which we believe could support current production levels for more than 25 years based on our 2020 production levels. Our reserve base in Met consists of 441.1 million tons of proven and 178.0 million tons of probable reserves, of which 91% is met coal. Our reserve base in CAPP - Thermal consists of 3.9 million tons of proven and 0.5 million tons of probable reserves, of which 100% is thermal coal.

Through our operations and reserves across coal producing basins 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 over a decade. We are continuously evaluating opportunities to strategically cultivate current relationships to drive new business in our target growth markets that include India and Southeast Asia, among others. In addition, our experienced management team regularly analyzes acquisitions, joint ventures and other opportunities that would be accretive and synergistic to our existing asset portfolio.

During 2020, we began production at Road Fork 52, Black Eagle and Lynn Branch which were previously identified organic met coal opportunities within Met. Road Fork 52 and Lynn Branch are primarily reserve replacement mines, but they are expected to provide some incremental production of Low-Vol. and High-Vol. B+ met coal, respectively. The Black Eagle mine is expected to increase production of Marfork High-Vol met coal. Production at these adjacent mines provides embedded growth potential while utilizing existing infrastructure.

Our History

We were formed 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 in 2016. 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. Refer to Note 16 for further information on our acquisition-related obligations.

We began operations on July 26, 2016 and currently operate mines in the Central Appalachia region.

On December 8, 2017, we closed a transaction with Blackjewel L.L.C. (“Buyer” or “Blackjewel”) to sell our Eagle Butte and Belle Ayr mines located in the Powder River Basin (“PRB”), Wyoming, along with related coal reserves, equipment, infrastructure and other real properties. Refer to Note 3 for information related to Blackjewel’s subsequent bankruptcy filing and the related ESM Transaction.

We merged with Alpha Natural Resources Holdings, Inc. and ANR, Inc. on November 9, 2018. 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 Northern Appalachia (“NAPP”) operations). This transaction accelerated our strategic exit from thermal coal production to shift our focus to met coal production.

The former PRB and NAPP operations results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements. The historical information in the accompanying Notes to the Consolidated Financial Statements has been restated to reflect the effects of these former operations being reported as discontinued operations in the Consolidated Financial Statements. Refer to Note 3 for further information on discontinued operations.

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.

The following tables present a summary of our mining operations by reportable segment:

We consider Deep Mine 41, Road Fork 52, Black Eagle, and Lynn Branch in Met to be individually material mines.

Our Met operations consist of high-quality met coal mines, including Deep Mine 41, Road Fork 52, Black Eagle, and Lynn Branch. The coal produced by Met operations is predominantly met coal with some amounts of thermal coal being produced as a byproduct of mining. The following table provides a summary of our Met operations’ coal qualities during the years ended December 31, 2020 and 2019:

During the years ended December 31, 2020 and 2019, we shipped 9.1 million tons and 8.4 million tons, respectively, of our coal production from our Met operations internationally to customers in Europe, Asia and the Americas, with the remaining met coal production sold into the domestic market. See Item 2. Properties, Costs & Calculations, for the two-year historical average sales prices.

Deep Mine 41, associated with the McClure Prep Plant, is located in Dickenson County, Virginia on property subject to a lease dated April 1, 2003. We can automatically extend the lease until March 31, 2063. The McClure Plant is a 1,000 ton per hour plant that is located on owned property in Dickenson County, Virginia. It was built in 1979 and upgraded in 1998.

Road Fork 52 is located in Wyoming County, West Virginia on three individual lease tracts. These leases were signed between 1960 and 2020. Current production is on a lease dated August 25, 1997. After expiration of the initial 10-year term of this lease, the lease automatically extended for successive five-year periods. The current five-year period expires August 24, 2022 and shall be renewed for another five-year period unless a 90-day termination notice is provided by the lessee. There will be future production on a lease dated January 28, 2020 which has a term of 20 years, and a lease dated August 1, 1960 which extends for successive 30 year terms until the mineable and merchantable coal is exhausted.

Black Eagle is located in Boone and Raleigh County, West Virginia near the community of Pettus. The reserve area is composed of five individual leases signed between 1929 and 2018 with various extension terms and periods. The majority of the reserve is located on a lease dated January 1, 1956 that expires on December 31, 2024. The earliest lease expiration date without renewal rights is December 21, 2022. It is customary to enter into new leases once the final extension period has expired.    

Lynn Branch deep mine in the 2 Gas seam is located in Logan County, West Virginia near the community of Rita. There are several leases dedicated to the mine with the primary reserves controlled by a lease dated January 1, 1969, which currently expires on December 31, 2026. We can automatically extend the lease for three successive five-year terms until December 31, 2041. All other leases are in good standing with similar lease terms.    

As of December 31, 2020, our CAPP - Thermal operations consist one underground thermal coal mine. The coal produced by CAPP - Thermal operations is predominantly thermal coal with some met coal byproduct. For the years ended December 31, 2020 and 2019, our CAPP - Thermal coal quality was composed of low sulfur, high BTU coal. During the years ended December 31, 2020 and 2019, we shipped 1.8 million tons and 3.5 million tons of our thermal coal production from our CAPP - Thermal operations domestically to utility and industrial customers.

Financial Information About Reportable Segments and Geographic Areas

Mine Life

The following table provides a summary of mine life for our active mines by segment, as of December 31, 2020:

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

Certain of our mines 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.

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.

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

We utilize highwall mining methods at 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.

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 customer needs and requirements. By offering coal of various types and grades to provide specific qualities of heat content, sulfur and ash and other characteristics relevant to our customers, we are able to serve a global customer base. Through this global platform, our coals are shipped to customers on five continents. This diversity 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 small volumes 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 operations also include met coal volumes purchased from domestic third-party producers and sold into international markets.

Our export shipments serviced customers through shipping ports in 23 and 22 countries during the years ended December 31, 2020 and 2019, respectively. Europe was our largest export market during these periods, with coal sales to Europe accounting for approximately 34% and 37%, respectively, of export coal revenues and 22% and 22%, respectively, of coal revenues for the years ended December 31, 2020 and 2019. All of our sales are made in U.S. dollars. Refer to Note 24 for additional export coal revenue information.

Our metallurgical coal sales are typically made with customers with whom we have a long-term relationship. However, defined pricing and volume in our sales agreements tend to be short-term in nature. Domestic metallurgical 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. Future volume for future years is generally contingent on both parties agreeing to a pricing mechanism to cover the contract year.

We enter into long-term contracts (typically ranging from one to five years) 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, 2020 and 2019, approximately 71% and 45%, 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 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 2020 and 2019, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers

Equipment

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

Procurement

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 metallurgical coal market, of the approximately 59 million tons produced in the U.S. in 2020, we sold approximately 12.4 million tons, or 21%. A significant portion of U.S. metallurgical coal production is shipped internationally, where it competes directly with international sources of production. Approximately 73% of our metallurgical coal sold was shipped internationally in 2020.

In the thermal market, of the approximately 475 million tons produced in the U.S. in 2020, we sold approximately 3.2 million tons, or almost 1%. Only a small portion of overall U.S. thermal production is shipped internationally, but there is strong competition in the domestic market. Approximately 21% of our thermal coal sold was shipped internationally in 2020. 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. The key factors of this competition are delivered coal price, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Competition from coal with lower production costs shipped from other coal basins has resulted in increased competition for coal sales in the Appalachian region.

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

Demand for thermal coal and the prices that we are able to obtain for it are closely linked to coal consumption patterns of the domestic electric generation industry. These coal consumption patterns are influenced by many factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures, and commercial and industrial outputs in the U.S., environmental and other government regulations, technological developments and the

location, availability, quality and price of competing sources of power. These competing sources include natural gas, nuclear, fuel oil and increasingly, renewable sources such as solar and wind power. Demand for thermal coal and the prices that we are able to obtain for it are affected by each of the above factors.

As of December 31, 2020, we had approximately 3,250 employees, all of which are full-time employees, with the United Mine Workers of America (“UMWA”) representing approximately 3% of these employees. 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. Relations with organized labor are important to our success, and we believe that we have good relations with our employees.

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.

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 extent of which we cannot predict. In particular, the new presidential administration and congressional majorities have expressed support for policies that may result in stricter environmental, health and safety standards applicable to our operations and those of our customers. We intend to continue to comply with these 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, 2020, we had accrued $165.1 million for reclamation liabilities and mine closures, including $25.0 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 Bankruptcy Court entered an order approving the sale by Blackjewel of the Belle Ayr and Eagle Butte mines located in the PRB (the “Western Assets”) to Eagle Specialty Materials, LLC (“ESM”). The closing of the ESM acquisition (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

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 that 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

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, 2021, is $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal. Future legislation is expected to extend these fees through 2028 at reduced rates. For the years ended December 31, 2020 and 2019, we recorded $2.3 million and $2.5 million, respectively, of expense related to these fees.

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

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, 2020 and 2019, our posted third-party surety bond amount in all states where we operate was approximately $351.6 million and $343.7 million, respectively, including portions attributable to discontinued operations of $134.2 million and $119.9 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, 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:

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. will withdraw from the Paris Agreement. This withdrawal formally took effect on November 4, 2020. However, on January 20, 2021, President Biden issued a statement formally accepting the Paris Agreement on behalf of the U.S., which triggers a 30 day process for rejoining the accord. In addition, numerous U.S. governors, mayors and businesses have pledged their commitments to the goals of the Paris Agreement. These commitments 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.

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

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

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

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

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

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

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

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.

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 January 13, 2021, the COE published its final rule reissuing and modifying a portion of its Nationwide permits. The COE reissued and modified 12 existing Nationwide permits and issued four new permits. The 12 reissued permits replace the 2017 versions which now expire March 14, 2021. The COE 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 U.S. Army Corps of Engineers (the “USACE”) 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. 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

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.

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.

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

RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are

warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. In December 2014, the EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rules also require fugitive dust controls and impose various monitoring, cleanup, and closure requirements. In July 2018, the EPA published a final rule extending certain deadlines under the original rules, granting certain authority to states with authorized CCR programs and establishing groundwater protection standards for certain constituents. The EPA and OSM plan additional rulemaking relating to CCR.

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

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

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

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

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

In 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act (the “MINER Act”). The MINER Act significantly amended the Mine Act, requiring, among other items, improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and severity of enforcement actions 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. 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, 2019, the trust fund was funded by an excise tax on production of up to $0.50 per ton for deep-mined coal and up to $0.25 per ton for surface-mined coal, neither amount to exceed 2% of the gross sales price. Effective January 1, 2020, the trust fund is funded by an excise tax on coal sold of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. Absent further legislation, beginning in 2022, the trust fund will be funded by an excise tax on coal sold of up to $0.50 per ton for deep-mined coal and up to $0.25 per ton for surface-mined coal, neither amount to exceed 2% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. For the years ended December 31, 2020 and 2019, we recorded $5.1 million and $2.9 million excluding portions attributable to discontinued operations, 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. These changes could have a material impact on our costs expended in association with the federal black lung program. For former mining employees meeting statutory eligibility standards for federal black lung benefits, we maintain a trust fund and insurance coverage to cover the cost of present and future claims. We may also be liable under state laws for black lung claims that are covered through the trust and insurance policies. The liability associated with present and future claims for black lung benefits is difficult to estimate, and the trust and insurance policies may be insufficient to cover all such liability.

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.

Investment in our common stock is subject to various risks, including risks and uncertainties inherent in our business. These risks include, but are not limited to, the following:

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

Sustained low coal prices, or further declines in coal prices, would adversely affect revenues, operating results, cash flows, financial condition, stock price and the value of our coal reserves.

Our results of operations are substantially dependent upon the prices we receive for our coal. Those prices depend upon factors beyond our control (some of which are described in more detail in other risk factors below), including:

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

A period of sustained low demand for metallurgical coal (or “met coal”), by U.S. and foreign steel producers and the potential for negative trade impacts resulting from changing tariff policies, could reduce the price of our met coal, which would reduce our revenues.

Alpha produces met coal that is sold directly to both U.S. and foreign steel industry customers and indirectly to foreign steel industry customers through U.S.-based companies. Met coal accounted for approximately 87% of our coal revenues for the year ended December 31, 2020. Any deterioration in conditions in the U.S. or foreign steel industries, including the demand for steel and the continued financial viability of the industry, could reduce the demand for our met coal and could impact the collectability of our accounts receivable from U.S. or foreign steel industry customers.

The demand for foreign-produced steel both in foreign markets and in the U.S. market also depends on factors such as tariff rates on steel. On March 8, 2018, President Trump signed proclamations imposing a 25% tariff on imports of steel mill products and a 10% tariff on imports of wrought and unwrought aluminum. Alpha’s export customers include foreign steel producers who may be affected by the tariffs to the extent their production is imported into the U.S. Conversely, demand for met coal from our domestic customers may increase. Retaliatory tariffs by foreign nations have already limited international trade and may adversely impact global economic conditions.

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

Our ability to obtain financing and other services, and the form and degree of these services available to us, may be significantly limited by the lending, investment and similar policies of financial institutions and insurance companies regarding carbon energy producers and the environmental impacts of coal combustion.

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

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

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

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

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

exchange rates may provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to offer lower prices for coal to customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business-Competition.” Similarly, currency fluctuations could adversely affect demand for U.S. steel.

Lower demand for U.S. coal exports would reduce our foreign sales, could negatively impact our revenues and could result in downward pressure on domestic coal prices.

Coal export revenues accounted for approximately 64% of our coal revenues for the year ended December 31, 2020. In addition to the factors described above, demand for and viability of U.S. coal exports is dependent upon a number of factors outside of our control, including ocean freight rates and port and shipping capacity.

In addition, trade conflicts between the United States and other nations that result in the imposition of barriers to trade, such as import tariffs, could materially and adversely affect the international demand and pricing for our coal. The United States has, during recent years, taken actions, including imposing tariffs on certain goods imported into the U.S., that have resulted in other nations adopting retaliatory measures such as the imposition of tariffs upon goods imported from the U.S. into those nations. China and Turkey, for example, have imposed tariffs upon the importing of coal from the U.S. The imposition of these trade barriers by other nations has already resulted in adverse effects upon our international sales of coal, including reduced demand and prices. If these barriers endure, or are enhanced, our coal exports may further decline, and increased domestic supply could cause competition among coal producers in the U.S. to intensify, potentially resulting in additional downward pressure on domestic coal prices and our business, financial condition or results of operations.

Chinese governmental policies as well as trade disputes in Asian markets may continue to be detrimental to the global coal market and negatively affect our business, financial condition or results of operations.

The Chinese government has from time to time implemented regulations and promulgated new laws or restrictions on its domestic coal industry, sometimes with little advance notice, which may impact worldwide coal demand, supply and prices. During the past several years, the Chinese government has initiated a number of anti-smog measures aimed at reducing hazardous air emissions through temporary production capacity restrictions within the steel, coal and coal-fired power sectors. It is possible that policy changes by the Chinese government may be detrimental to the global coal market and, thus, negatively affect our business, financial condition or results of operations. Further, similar actions by government entities in countries that produce and/or consume large quantities of coal and other energy related commodities, such as India, may have a material impact on the prices at which we sell our product.

In addition, certain trade disputes in Asian markets, such as those between China and Australia, have resulted in increased coal supply and lower prices in non-Asian markets to which we export our coal. Should these disputes endure, continued lower prices in certain of our export markets may have significant negative effects on our business, financial condition or results of operations.

The concurrent loss of, or significant reduction in, purchases by several of our largest customers could materially and adversely affect our revenues and profitability.

Our largest customer during the year ended December 31, 2020 accounted for approximately 16% of our total revenues, and coal sales to our 10 largest customers accounted for approximately 63% of our total revenues. These customers could decide to discontinue purchasing coal from us in the volumes that they have previously purchased or decide to not purchase at all. If several of these customers were concurrently to reduce their purchases of coal significantly, or if we were unable to sell coal to them on terms as favorable to us as previous sales, we could face a significant reduction in sales while we attempt to sell the coal to other customers in the global marketplace. If this concurrent loss or significant reduction were to happen, our revenues and profitability could be materially and adversely affected.

Continuing low demand for thermal coal, or further declines in demand, by North American electric power generators could reduce the price of our thermal coal, which would reduce our revenues.

Thermal coal accounted for approximately 13% of our coal revenues for the year ended December 31, 2020. The majority of our sales of thermal coal were to U.S. electric power generators. The North American demand for thermal coal is affected primarily by:

Many North American electric power generators have shifted from coal to natural gas-fired power plants. Despite ongoing advancements in the availability and deployment of advanced coal and emissions reduction technologies, we expect that new power plants in the near-term will be fired by natural gas because natural gas-fired plants are less expensive to construct than coal-fired plants and natural gas is a cleaner-burning fuel, with plentiful supplies and low cost at the current time. Increasingly stringent regulations have also reduced the number of new power plants being built, particularly coal-fired power plants. A reduction in the amount of coal consumed by North American electric power generators would reduce the amount of thermal coal that we sell and the price that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. In addition, uncertainty caused by federal and state regulations could cause thermal coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to such customers under multi-year sales contracts.

We may not be able to extend our existing long-term supply contracts or enter into new ones, and our existing supply contracts may contain certain provisions that may reduce protection from short-term coal price volatility, which could adversely affect the profitability of our operations.

A substantial portion of our thermal coal is sold under long-term contracts. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on terms, including pricing terms, that are not as favorable to us as the terms under our current agreements.

Further, in large part as a result of increasing and frequently changing regulation, and natural gas pricing, electric power generators are increasingly less willing to enter into long-term coal supply contracts, instead purchasing higher percentages of coal under short-term supply contracts. This industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, our having fewer customers with a contractual obligation to purchase coal from us increases the risk that we will not have a consistent market for our production and may require us to sell more coal in the spot market, where prices may be lower than we would expect a customer to pay for a contractually committed supply. Spot market prices also tend to be more volatile than contractual prices, which could result in decreased revenues. Our met coal supply contracts are typically priced on an annual, quarterly or spot basis, and therefore our met coal sales are particularly sensitive to repricing risk.

Generally, our long-term thermal coal agreements contain committed volumes and fixed prices for a certain number of periods during which thermal coal will be delivered. However, some of our long-term thermal coal agreements do not provide for a fixed price through the life of the agreement. Those agreements contain price negotiation and similar provisions for upcoming unpriced contract periods, with negotiations generally considering either then current market prices and/or relevant market indices. Failure of the parties to agree on a price can lead to termination of the contract or litigation, the outcome of which would be uncertain. Further, during periods of economic weakness, some of our customers experience lower demand for their products and services and may be unwilling to take all of their contracted tonnage or may request a lower price. Customers may make similar requests when market prices drop significantly. Any adjustment or negotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse or volatile market conditions.

Competition with natural gas and renewable energy sources, and factors affecting these industries could have an adverse impact on coal demand.

Our coal competes with natural gas and renewable energy sources, and the price of these sources can therefore affect coal sales. The natural gas market has been volatile historically and prices in this market are subject to wide fluctuations in response to relatively minor changes in supply and demand. Changes in supply and demand could be prompted by any number of factors, such as worldwide and regional economic and political conditions; the level of global exploration, production and inventories; natural gas prices; and transportation availability. If natural gas prices decline significantly, it could lead to reduced coal sales and have a material adverse effect on our financial condition, results of operations and cash flows.

In addition, state and federal mandates for increased use of electricity from renewable energy sources also have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

Our ability to collect payments from our customers could be impaired if their creditworthiness and financial health deteriorate.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness and financial health of our customers. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. In recent years, downturns in the economy and disruptions in the global financial markets have, from time to time, affected the creditworthiness of our customers and limited their liquidity and credit availability. In addition, our customer base may change with deregulation as utilities sell or transfer their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. These new power plant owners or operators may have credit ratings that are below investment grade or may become below investment grade after we enter into contracts with them.

Customers in other countries may be subject to other pressures and uncertainties that may affect their ability to pay, including trade barriers, exchange controls and local economic and political conditions. For the year ended December 31, 2020 we derived 64% of our coal revenues from coal sales made to customers outside the U.S.

Downturns and disruptions in the global economy and financial markets have had, and could in the future have, a material adverse effect on the demand for and price of coal, which could have a material negative effect on our sales, costs, margins and profitability and ability to obtain financing.

Downturns and disruptions in the global economy and financial markets have from time to time resulted in, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, including real estate. Significant economic disruptions can result from numerous unpredictable factors, including but not limited to market forces, natural disasters, pandemics (such as the COVID-19 virus), trade disputes and armed conflicts. Future disruptions of this sort, and in particular the tightening of credit in financial markets or any other disruption that negatively affects global economic growth, could adversely affect our customers’ ability to obtain financing for operations and result in a decrease in demand, lower coal prices, the cancellation of some orders for our coal and the restructuring of agreements with some of our customers. Changes in the value of the U.S. dollar relative to other currencies, particularly where imported products are required for the mining process, could result in materially increased operating expenses. Any prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for and price of coal, on our sales, margins and profitability, and on our own ability to obtain financing. We are unable to predict the timing, duration and severity of any potential future disruptions in financial markets and potential future adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.

The extensive regulation of the mining industry imposes significant costs on us, and future regulations or violations could increase those costs or limit our ability to produce coal.

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

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

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

We incur substantial costs to comply with the laws, regulations and permits that apply to our mining and other operations, and to address the outcome of inspections. The required compliance and actions to address inspection outcomes are often time-consuming and may delay commencement or continuation of exploration or production. In addition, due in part to the extensive and comprehensive regulatory requirements, violations of laws, regulations and permits occur at our operations from time to time and may result in significant costs to us to correct the violations, as well as substantial civil or criminal penalties and limitations or shutdowns of our operations. In particular, President Biden and the current Congressional majorities have expressed support for policies that may result in stricter environmental, health and safety standards applicable to our operations and those of our customers. For example, on January 20, 2021, President Biden issued an executive order titled “Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” (the “January 20 Executive Order”) which among other things, calls for a review of regulations and other executive actions issued during the prior Presidential administration to assess whether they are, in the view of the Biden administration, sufficiently protective of public health and the environment, including with respect to climate change, and consistent with science. See “Environmental and Other Regulatory Matters—Clean Water Act—Wastewater Discharge.”

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

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

Climate change or carbon dioxide emissions reduction initiatives could significantly reduce the demand for coal and reduce the value of our coal assets.

Global climate issues continue to attract considerable public and scientific attention. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, and in particular the emissions of GHG, such as carbon dioxide and methane, on global climate issues. Combustion of fossil fuels like coal results in the creation of carbon dioxide, which is emitted into the atmosphere by coal end users such as coal-fired electric power generators, coke plants and steelmaking plants, and, to a lesser extent, by the combustion of fossil fuels by the mining equipment we use. In addition, coal mining can release methane from the mine, directly into the atmosphere. Concerns associated with global climate change, and GHG emissions reduction initiatives designed to address them, have resulted, and are expected to continue to result, in 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 coal.

Emissions from coal consumption and production are subject to pending and proposed regulations as part of regulatory initiatives to address global climate change and global warming. Various international, federal, regional, foreign and state proposals are currently in place or being considered to limit emissions of GHGs, including possible future U.S. treaty

commitments, new federal or state legislation, and regulation under existing environmental laws by the EPA and other regulatory agencies and litigation by private parties. These include:

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

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

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

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

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

Other extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions, waste management and water discharges, affect our customers and could further reduce the demand for coal as a fuel source and cause prices and sales of our coal to materially decline.

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

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

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

The U.S. Internal Revenue Service could withhold tax refunds and assert a right to setoff against pre-petition claims of the U.S. government during the Alpha Natural Resources, Inc. bankruptcy, which could have a material adverse effect upon the Company’s assets.

As of December 31, 2020, the Company has recorded $64.2 million of current federal income tax receivable and associated interest receivable of $5.2 million related to a net operating loss (“NOL”) carryback claim. Because the federal government was a creditor in the Alpha Natural Resources, Inc. bankruptcy proceedings, it is possible that the federal government could withhold some or all of the tax refund attributable to the NOL carryback claim and assert a right to set off the tax refund and associated interest receivable against its prepetition bankruptcy claims. If the IRS were to take such actions, the Company would vigorously defend its position. However, if the Company were unsuccessful, there could be a material, adverse effect upon the Company’s assets.

Decreases in consumer demand for electricity and changes in general energy consumption patterns attributable to energy conservation trends could adversely affect our business, financial condition and results of operations.

Due to efforts to promote energy conservation in recent years, there is a risk that both the demand for electricity and the general energy consumption patterns of consumers worldwide will decrease. The ability of energy conservation technologies, public initiatives and government incentives to reduce electricity consumption or to support other forms of renewable energy could also lead to a reduction in the price of coal. If prices for coal are not competitive, our business, financial condition and results of operations may be materially harmed.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

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

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

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

We may be unable to obtain and renew permits, mine plan modifications and approvals, leases or other rights necessary for our operations, which would reduce our production, cash flows and profitability.

Mining companies must obtain numerous regulatory permits that impose strict conditions on various environmental and safety matters in connection with coal mining. The permitting rules are complex and change over time, potentially in ways that may make our ability to comply with the applicable requirements more difficult or impractical or even preclude the continuation of ongoing operations or the development of future mining operations. The public, including special interest groups and individuals, have certain rights under various statutes to comment upon, submit objections to and otherwise engage in the permitting process, including bringing citizens’ lawsuits or administrative actions to challenge permits or mining activities. In states where we operate, applicable laws and regulations also provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls or is under common ownership or control with us or is determined to be linked to us under OSM’s AVS, have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including being an officer or director of an entity or owning between 10% and 50% of the mining operator. This presumption, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which the relevant coal mining operation is conducted. Thus, past or ongoing violations of federal and state mining laws by us or by coal mining operations owned or controlled by our significant stockholders, directors or officers or by entities linked to us through OSM’s AVS could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. This is known as being “permit-blocked.” In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

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

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

In January 2020, the EPA and the U.S. Army Corps of Engineers (the “USACE”) 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. 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. The Navigable Waters Protection Rule is designed to fulfill a February 2017 executive order calling on the EPA and the USACE to develop a rule consistent with Justice Antonin Scalia's plurality opinion in the 2006 Supreme Court decision, Rapanos v. United States, that CWA jurisdiction attaches only to “navigable waters” and other waters with a relatively permanent flow, such as rivers or lakes. The Navigable Waters Protection Rule narrows the jurisdiction of the CWA relative to Clean Water Rule by, among other things, excluding from the scope of the definition of “waters of the United States” certain ephemeral streams and wetlands not adjacent to jurisdictional water bodies. The Navigable Water Protection Rule is likely to be the subject of legal challenges and potential reconsideration by the EPA and its ultimate impact on our operations is uncertain.

Additionally, we may rely on nationwide permits under the CWA Section 404 program for some of our operations. These nationwide permits are issued every five years, and the 2017 nationwide permit program was recently reissued in January 2017. If we are unable to use the nationwide permits and require an individual permit for certain work, that could delay operations.

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

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

Federal and state regulatory agencies have the authority to order any of our facilities to be temporarily or permanently closed under certain circumstances, which could materially adversely affect our ability to meet our customers’ demands.

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

In connection with the Alpha Natural Resources, Inc. Restructuring settlement, we and Alpha Natural Resources, Inc. entered into a number of agreements with state and federal agencies regarding the funding, performance and bonding of reclamation and other environmental restoration obligations with respect to mine properties retained by Alpha Natural Resources, Inc. under the Alpha Natural Resources, Inc. Restructuring. These agreements have been amended from time to time in connection with sales by Alpha Natural Resources, Inc. of certain of these properties. These agreements require us to make periodic payments to certain accounts designated to fund reclamation and other activities at various facilities and also impose bonding, reporting and other obligations. A failure to fulfill our obligations under these agreements could be considered an event of default which could result in, among other things, the cancellation of certain permits, a termination of the agreement and the taking of any regulatory or enforcement action that an agency enforcing such default is permitted to take.

Our systems and procedures for internal control over financial reporting or the disclosure controls related to them may in the future have material weaknesses, which may adversely affect the value of our common stock.

We are responsible for maintaining systems and documentation necessary to evaluate the effectiveness of our internal control over financial reporting. These activities may divert management’s attention from other business concerns. To maintain

and improve our controls and procedures, we must commit significant resources, may be required to hire additional staff and need to continue to provide effective management oversight, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Certain U.S. federal income tax provisions currently available with respect to coal percentage depletion and exploration and development may be eliminated by future legislation.

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

Changes in tax laws, particularly in the areas of non-income taxes, or obligations arising from audits of royalties previously paid to government entities, could cause our financial position and profitability to deteriorate.

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

In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting our cost of providing healthcare benefits to our employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease). The PPACA has both short-term and long-term implications on benefit plan standards. Implementation of this legislation is expected to extend through 2020. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase due to, among other things, an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual.

The PPACA planned to impose a 40% excise tax on employers beginning in 2022 to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. In December 2019, the excise tax was repealed before it could take effect, effective for taxable years beginning after December 31, 2019.

Our coal mining production and delivery is subject to conditions and events beyond our control that could result in higher operating expenses and decreased production and sales. The occurrence of a significant accident or other event that is not fully insured could adversely affect our business and operating results and could result in impairments to our assets.

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

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

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

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

A decline in demand for met coal would limit our ability to sell our high quality thermal coal as higher priced met coal, which would reduce our revenues and profitability, and could affect the economic viability of some of our mines with higher operating costs.

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

Mining in Central Appalachia is more complex and involves more regulatory constraints than mining in other areas of the U.S., which could affect our mining operations and cost structures in these areas.

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

Disruptions in transportation services and increased transportation costs could impair our ability to supply coal to our customers, reduce demand and adversely affect our business.

For the year ended December 31, 2020, 80% of our coal volume was transported from our shipping points to a vessel loading point or customer location by rail. Deterioration in the reliability of the service provided by rail carriers would result in increased internal coal handling costs and decreased shipping volumes, and if we are unable to find alternatives, our business could be adversely affected. Some of our operations are serviced by a single rail carrier. Due to the difficulty in arranging alternative transportation, these operations are particularly at risk to disruptions, capacity issues or other difficulties with that carrier’s transportation services, which could adversely impact our revenues and results of operations.

We also depend upon trucks, beltlines, ocean vessels and barges to deliver coal to our customers. In addition, much of our eastern coal is transported from our mines to our loading facilities by trucks owned and operated by third parties. Disruption of any of these transportation services due to weather-related problems, mechanical difficulties, fuel and supply costs, strikes,

lockouts, bottlenecks, terrorist attacks and other events could impair our ability to supply coal to our customers, resulting in decreased shipments and revenue. Disruption in shipment levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and results of operations.

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

We require a skilled workforce to run our business. If we cannot hire and retain qualified persons to meet replacement or expansion needs, we may not be able to achieve planned results.

Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers and supervisors. The demand for skilled employees sometimes causes a significant constriction of the labor supply resulting in higher labor costs. We, along with the mining industry generally, are currently facing a shortage of experienced mechanics and certified electricians. When coal producers compete for skilled miners, recruiting challenges can occur and employee turnover rates can increase, which negatively affect operating efficiency and costs. If a shortage of skilled workers exists and we are unable to train or retain the necessary number of miners, it could adversely affect our productivity, costs and ability to expand production.

In addition, we depend on the experience and industry knowledge of our officers and other key employees to design and execute our business plans. If we experience a substantial turnover in our leadership and other key employees, and these persons are not replaced by individuals with comparable skills, our performance could be materially adversely impacted. Furthermore, we may be unable to attract and retain additional qualified executives as needed in the future.

Certain provisions in our coal supply agreements may result in economic penalties upon our failure to meet specifications.

Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as BTU, sulfur content, ash content, grindability, moisture and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Further, some of our coal supply agreements allow our customers to terminate the contract in the event of regulatory changes that restrict the type of coal the customer may use at its facilities or the use of that coal or increase the price of coal or the cost of using coal beyond specified limits. In addition, our coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during specified events beyond the control of the affected party. As a result of these issues, we may not achieve the revenue or profit we expect to achieve from our coal supply agreements.

Expenditures for certain employee benefits could be materially higher than we have anticipated, which could increase our costs and adversely affect our financial results.

We are responsible for certain liabilities under a variety of benefit plans and other arrangements with employees. The unfunded status of these obligations, including discontinued operations, as of December 31, 2020 included $97.4 million of workers’ compensation obligations, net of expected insurance receivable amounts, $218.7 million of pension obligations, and $124.8 million of black lung obligations. These obligations have been estimated based on assumptions including actuarial estimates, discount rates, and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.

If the assumptions underlying our accruals for reclamation and mine closure obligations prove to be inaccurate, we could be required to expend greater amounts than anticipated.

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Our estimated total reclamation and mine-closing liabilities were $165.1 million as of December 31, 2020, based upon permit requirements and the historical experience at our operations, and depend on a number of variables involving assumptions and estimation and therefore may be subject to change, including the estimated future asset retirement costs and the timing of such costs, estimated proven reserves, assumptions involving profit margins of third-party contractors, inflation rates and discount rates. Furthermore, these obligations are primarily unfunded. If these accruals are insufficient or our

liability in a particular year is greater than currently anticipated, our future operating results and financial position could be adversely affected. In addition, significant changes from period to period could result in significant variability in our operating results, which could reduce comparability between periods and impact our liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for a description of our estimated costs of these liabilities.

Estimates of our economically recoverable coal reserves involve uncertainties, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.

We base our estimates of our economically recoverable coal reserves on engineering, economic and geological data assembled and analyzed by our staff, including various engineers and geologists, and periodically reviewed by outside firms. Our estimates as to the quantity and quality of the coal in our reserves are updated annually to reflect production of coal from the reserves and new drilling, engineering or other data. These estimates depend upon a variety of factors and assumptions, many of which involve uncertainties and factors beyond our control and may vary considerably from actual results, such as:

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

Our business will be adversely affected if we are unable to timely develop or acquire additional coal reserves that are economically recoverable.

Our profitability depends substantially on our ability to mine in a cost-effective manner coal reserves of the quality our customers need. Although we have coal reserves that we believe could support current production levels for more than 35 years, we have not yet developed the mines for all our reserves. We may not be able to mine all of our reserves as profitably as we do at our current operations. Under adverse market conditions, some reserves could not be mined profitably at all. In addition, in order to develop our reserves, we must receive various governmental permits. As discussed above, some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. We may be unable to obtain the necessary permits on terms that would allow us to operate profitably or at all.

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

If we are unable to acquire surface rights to access our coal reserves, we may be unable to obtain a permit to mine coal we own and may be required to employ expensive techniques to mine around those sections of land we cannot access in order to access other sections of coal reserves, which could materially and adversely affect our business and our results of operations.

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

Our workforce could become increasingly unionized in the future and our unionized or union-free workforce could strike, which could adversely affect the stability of our production and reduce our profitability.

Approximately 97% of our total workforce and approximately 95% of our hourly workforce was union-free as of December 31, 2020. However, under the National Labor Relations Act, employees have the right at any time to form or affiliate with a union. Any further unionization of our employees or the employees of third-party contractors who mine coal for us could adversely affect the stability of our production and reduce our profitability.

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

Conflicts with competing holders of mineral rights and rights to use adjacent, overlying or underlying lands could materially and adversely affect our ability to mine coal or do so on a cost-effective basis.

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

Cybersecurity attacks, natural disasters, terrorist attacks and other similar crises or disruptions may negatively affect our business, financial condition and results of operations, or those of our customers and suppliers.

Our business, or the businesses of our customers and suppliers, may be impacted by disruptions such as cybersecurity attacks or failures, threats to physical security, and extreme weather conditions or other natural disasters. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cybersecurity attacks than other targets in the U.S. These disruptions or any significant increases in energy prices that follow could result in government-imposed price controls. Our insurance may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cybersecurity attacks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cybersecurity attacks.

Provisions in our lease agreements, defects in title in our mine properties or loss of leasehold rights could limit our ability to recover coal from our properties or result in significant unanticipated costs.

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

minimum quantity of coal and/or pay minimum production royalties. If those requirements are not met, the leasehold interest may terminate.

Decreased availability or increased costs of key equipment and materials, including certain items mandated by regulations, or of coal that we purchase from third parties, could impact our cost of production and decrease our profitability.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires, steel, magnetite and other raw materials and consumables which, in some cases, do not have ready substitutes. Some equipment and materials are needed to comply with regulations, such as proximity detection devices on continuous mining machines. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

In addition, the prices we pay for these materials are strongly influenced by the global commodities markets. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. If the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially adversely impact our profitability. Some materials, such as steel, are needed to comply with regulatory requirements. Furthermore, operating expenses at our mining locations are sensitive to changes in certain variable costs, including diesel fuel prices, which is one of our largest variable costs. Our results depend on our ability to adequately control our costs. Any increase in the price we pay for diesel fuel will have a negative impact on our results of operations. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices.

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

We have previously and may in the future contract with third-parties to operate or reclaim certain of our mines, and our results of operations could be adversely affected if these operators are ineffective.

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

Strategic transactions, including acquisitions, involve a number of risks, any of which could result in a material adverse effect on our business, financial condition or results of operations.

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

Risks inherent in these strategic transactions include:

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

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

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

We may be unable to generate sufficient taxable income from future operations, or other circumstances could arise, which may limit our ability to utilize our tax net operating loss carryforwards or maintain our deferred tax assets.

We acquired the core coal assets of Alpha Natural Resources, Inc. as part of Alpha Natural Resources, Inc.’s bankruptcy restructuring in transactions intended to be treated as a tax-free reorganization for U.S. federal income tax purposes. As a result of these transactions, we inherited the tax basis of the core assets and the net operating loss and other carryforwards of Alpha Natural Resources, Inc. These carryforwards and tax basis were subject to reduction on December 31, 2016 due to the cancellation of indebtedness resulting from Alpha Natural Resources, Inc.’s bankruptcy restructuring. Due to the change in ownership, the net operating loss and other carryforwards will be subjected to limitations on their use in future years and additional changes in ownership in future years may further reduce the annual amount of the net operating loss and other carryforwards available to be utilized. In addition, we do not have a long history of operating results, and if we are unable to generate profits in the future, we may be unable to utilize these carryforwards. As of December 31, 2020, a valuation allowance of $263.4 million has been provided on federal and state net operating loss carryforwards and other deferred tax assets not expected to provide future tax benefits.

Negative or unexpected consequences of the Tax Cuts and Jobs Act could affect our business.

On December 22, 2017, legislation commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”) significantly revised U.S. federal corporate tax law by, among other things, reducing the U.S. federal corporate income tax rate to 21%, eliminating the corporate alternative minimum tax, providing a mechanism for corporations to monetize alternative minimum tax credits (“AMT Credits”), limiting the tax deduction for interest expense to 30% of adjusted earnings, allowing immediate expensing for certain new investments, and, effective for net operating losses arising in taxable years beginning after December 31, 2017, eliminating net operating loss carrybacks, permitting indefinite net operating loss carryforwards, and limiting the use of net operating loss carryforwards to 80% of current year taxable income.

There are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the TCJA. In the absence of guidance of these issues, we will use what we believe are reasonable interpretations and assumptions in interpreting and applying the TCJA for purposes of determining our cash tax liabilities and results of operations, which may change as we receive additional clarification and implementation guidance and as the interpretation of the TCJA evolves over time. It is possible that the IRS could issue subsequent guidance or take positions on audit that differ from the interpretations and assumptions that we previously made, which could have a material adverse effect on our cash tax liabilities, results of operations and financial condition.

Our business requires substantial capital investment and maintenance expenditures, which we may be unable to provide.

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

Changes in the fair value of liabilities that are marked to market could cause volatility in our earnings.

Pursuant to the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession, dated May 27, 2016, as modified and confirmed by the Order Confirming Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession, as Modified (Docket No. 3038), entered by the Bankruptcy Court on July 12, 2016, we have contingent revenue payment obligations to certain of Alpha Natural Resources Inc.’s creditors, which are recorded at fair market value and marked to market in each reporting period, with changes in value reflected in earnings. Any change in fair value can have a significant impact on our earnings from period to period, including in the future.

Our indebtedness exposes us to various risks.

At December 31, 2020, we had $599.6 million of indebtedness outstanding before discounts and issuance costs applied for financial reporting, of which $62.9 million will mature in the next three years.

Our indebtedness could have important consequences to our business. For example, it could:

Our ability to meet our debt service obligations will depend on our future cash flow from operations and our ability to restructure or refinance our debt, which will depend on the condition of the capital markets and our financial condition at that

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

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs (including related to black lung), coal leases and other obligations. These bonds are typically renewable annually. Under applicable regulations, self-bonding may not be available to us as a means to comply with our reclamation bonding obligations for the foreseeable future. Surety bond issuers and holders may not continue to renew the bonds, may demand less favorable terms upon renewal or may impose new or increased collateral requirements. As of December 31, 2020, we had outstanding surety bonds with third parties of approximately $351.6 million, including $134.2 million attributable to discontinued operations. Surety bond issuers and holders may demand additional collateral, unfavorable terms or higher fees. Our failure to retain, or inability to acquire, surety bonds or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and results of operations. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds, restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place, or our inability to comply with our reclamation bonding obligations through self-bonding. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, depending on the amount of any cash collateral required, could have a material adverse impact on our liquidity and financial position. If we are unable to meet cash collateral requirements and cannot otherwise obtain or retain required surety bonds, we may be unable to satisfy legal requirements necessary to conduct our mining operations.

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

The terms of our credit facility impose operating and financial restrictions on us, which may limit our ability to respond to changing business and economic conditions.

In connection with the Credit Agreement entered into on June 14, 2019, we incurred indebtedness of approximately $562 million under a term loan credit facility to refinance existing indebtedness and to pay related fees and expenses. The term loan credit facility matures on June 14, 2024. The term loan credit facility permits us, subject to approval of the administrative agent and the lenders providing the financing, to request incremental term loans up to an aggregate amount of $50 million subject to certain conditions in the Credit Agreement, in increments not less than $25 million or the remaining availability.

In connection with the consummation of the Merger, we entered into the Amended and Restated Asset-Based Revolving Credit Agreement with a borrowing capacity of $225 million under a revolving credit facility. The revolving credit facility matures on April 3, 2022. Additionally, as a result of the Merger, we assumed a letter of credit agreement and a credit and security agreement which, among other things, include letter of credit facilities that provide for the issuance of letters of credit. The terms of our credit facilities impose operating and financial restrictions on us, which may limit our ability to respond to changing business and economic conditions. The revolving loan facility permits us, subject to approval of the administrative agent and the lenders providing the financing, to request incremental revolving commitment increases up to an aggregate amount of $50 million, in increments not less than $10 million or the remaining availability and subject to specified conditions.

We are subject to various operating and financial covenants under the term loan and revolving credit facilities which restrict our ability to, among other things, incur additional indebtedness, make particular types of investments, incur certain types of liens, engage in fundamental corporate changes, enter into transactions with affiliates, make substantial asset sales, make certain restricted payments, enter into amendments or waivers to certain agreements, conduct certain sale leasebacks or enter into certain burdensome agreements. Any failure to comply with these covenants may constitute a breach under the term loan and revolving credit facilities which could result in the acceleration of all or a substantial portion of any outstanding indebtedness and termination of revolving credit commitments under the term loan and revolving credit facilities. Our inability to maintain our term loan and revolving credit facilities could materially adversely affect our liquidity and our business. As of

December 31, 2020, we are in compliance with the operating and financial covenants under the term loan and revolving credit facilities.

Pressure on our business, cash flow and liquidity could materially and adversely affect our ability to fund our business operations or react to and withstand changing market and industry conditions. Additional sources of funds may not be available.

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

The terms of our borrowing arrangements limit our and our subsidiaries’ ability to take certain actions, which may limit our operating and financial flexibility and adversely affect our business.

Our borrowing arrangements contain, and any future borrowing arrangements are also likely to contain, a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness, enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital stock, make loans and investments, create liens, sell certain assets, engage in transactions with affiliates, and merge or consolidate with other companies or sell substantially all of our assets. These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions. We regularly evaluate opportunities to enhance our capital structure and financial flexibility through a variety of methods, including repayment or repurchase of outstanding debt, amendment of our credit facility and other facilities, and other methods. As a result of any of these actions, the restrictions and covenants that apply to us may become more restrictive or otherwise change.

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

The need to maintain capacity for required letters of credit could limit our ability to provide financial assurance for self-insured obligations and negatively impact our ability to fund future working capital, capital expenditure or other general corporate requirements.

On November 9, 2018, we entered into the Amended and Restated Asset-Based Revolving Credit Agreement. Additionally, as a result of the Merger, we assumed an Amended and Restated Letter of Credit Agreement and a Credit and Security Agreement. Each of these agreements includes, among other things, provisions that provide for the issuance of letters of credit. Obligations secured by letters of credit may increase in the future. If we do not maintain sufficient borrowing capacity under our letter of credit facilities, we may be unable to provide financial assurance for self-insured obligations and could negatively impact our ability to fund future working capital, capital expenditure or other general corporate requirements.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, require application of significant resources and management attention, and we may be unable to comply with these requirements in a timely or cost-effective manner.

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

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

An active, liquid and orderly trading market for our common stock may not be maintained, and our stock price may be volatile.

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

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

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may issue additional shares of common stock or convertible securities in subsequent public offerings. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock or the dividend amount payable per share on our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock or the dividend amount payable per share on our common stock. In addition, the issuance of shares of

common stock upon the exercise of outstanding options and warrants would result in dilution to the interests of other stockholders.

We may issue preferred stock with terms that could adversely affect the voting power or value of our common stock.

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

Provisions in our organizational documents and the instruments governing our debt may discourage a takeover attempt, even if doing so might be beneficial to our stockholders.

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

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

Our bylaws provide, subject to certain exceptions, that the Court of Chancery of the State of Delaware is the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

Our bylaws provide, subject to limited exceptions, that the Court of Chancery of the State of Delaware is, to the fullest extent permitted by law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders; (iii) any action asserting a claim against us, any director or our officers or employees arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation (including any certificate of designations relating to any class or series of preferred stock) or our bylaws; or (iv) any action asserting a claim against us, any director or our officers or employees that is governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock shall be deemed to have notice of and to have consented to the provisions of our bylaws described above. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, other employees or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision that is contained in our bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations.

None.

Coal Reserves

We prepared our estimates of reserves which were audited by Marshall Miller & Associates, Inc. (“MM&A”), and MM&A reviewed our methodology, assumptions and reserve factors utilized in determining these estimates. In the few instances where MM&A recommended revisions to reserve figures, MM&A worked with our team to modify reserve estimates. MM&A relied on their independent pro-forma economic analysis for ultimate reserve determination; this analysis is further discussed in the Costs & Calculations section below.

We maintain an internal staff of engineers and geoscience professionals who work closely with independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our estimated reserves. Our internal technical team members meet with independent reserve engineers periodically to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for their properties, such as ownership interest, production, test data, commodity prices and operating and development costs.

These estimates are based on engineering, economic and geologic data, coal ownership information and current and proposed mine plans. Our proven and probable coal reserves are reported as “recoverable coal reserves,” which is the portion of the coal that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will changes in preparation plant processes.

“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between “proven (measured) reserves” and “probable (indicated) reserves,” which are defined as follows:

On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures.

As of December 31, 2020, we had estimated reserves totaling 623.5 million tons, of which 331.1 million tons, or 53%, were “assigned” recoverable reserves that were either being mined, were controlled and accessible from a then active mine, or located at idled facilities where limited capital expenditures would be required to initiate operations when conditions warrant. The remaining 292.4 million tons were classified as “unassigned,” representing coal at currently non-producing locations that we anticipate mining in the future, but which would require significant additional development capital before operations could begin.

The following table provides the location and coal reserves associated with each of our reportable segments and related significant mines as of December 31, 2020:

As of December 31, 2020

The following table provides the breakdown between the quantity of reserves that is currently covered by an active mining permit or not permitted and the quantity of reserves that is met coal or thermal coal associated with each of our reportable segments and related significant mines as of December 31, 2020:

As of December 31, 2020

The following table provides a summary of the quality of our reserves for each of our reportable segments and related significant mines as of December 31, 2020:

As of December 31, 2020

The following table provides a summary of information regarding our mining operations for each of our reportable segments and related significant mines as of December 31, 2020:

The following table provides a summary of information regarding our significant preparation plants as of December 31, 2020:

Information provided within the previous tables concerning our properties has been prepared in accordance with applicable U.S. federal securities laws. All mineral reserve estimates have been prepared in accordance with SEC Industry Guide 7.

The following is a summary of information regarding our significant coal terminal as of December 31, 2020:

Costs & Calculations

Coal tonnage is classified as reserve when demonstrating profit on a fully loaded cost basis. Pro forma testing conducted by MM&A demonstrated that our reserves are expected to generate cash and are profitable on a fully loaded cost basis. Fully loaded costs were compared to two-year historical sales realizations for all potential reserve areas. The classification of reserves is dependent upon the sum of all costs normalized to a per clean ton basis being less than the two-year historical sales price. The two-year historical sales price includes the following average prices categorized by coal qualities:

For the surface mining reserve areas, the mining costs were estimated using the surface mining overburden ratios. Direct mining costs were estimated for labor, blasting, fuel and lubrication supplies, repairs and maintenance, operating supplies and other costs. The pro forma mining cost estimates for underground mining areas began with the computation of representative total seam thickness for each area evaluated. The clean-tons-per-foot of mining advance was calculated to support mine production and productivity calculations.

All underground and highwall miner coal reserves are expected to require washing to remove coal partings and out-of-seam contamination. Preparation plant yield was calculated by multiplying the in-seam recovery, out-of-seam contamination and plant efficiency factors. In-seam recovery factors were obtained based upon the relative percentages of coal and rock within the seam. Direct mining costs were estimated for labor, supplies, maintenance and repairs, mine power and other direct mining costs. Sales, general and administration and environmental cost allocations were based on values typically observed by MM&A. Sales variable costs for royalty payments, black lung excise tax and reclamation fees were calculated, along with cost components for other indirect mining costs.

The following map shows the locations of our significant properties, Met properties, CAPP - Thermal properties, and corporate headquarters.

For a description of the Company’s legal proceedings, refer to Note 23, part (d), to the Consolidated Financial Statements, which is incorporated herein by reference.

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.

Part II

Upon the consummation of the transactions contemplated by the Merger Agreement, we began trading on the New York Stock Exchange under the ticker “CTRA” on November 9, 2018. Following the effectiveness of our name change on February 1, 2021, our ticker symbol on the New York Stock Exchange changed from “CTRA” to “AMR” effective on February 4, 2021. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported on the New York Stock Exchange.

As of December 31, 2020, there were 155 registered holders of record of our common stock. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A. Our common stock is registered by book-entry only.

The payment of dividends is subject to certain limitations, as set forth in the terms of our borrowing arrangements. During the years ended 2020 and 2019, we did not pay dividends on our common stock. Our Board of Directors periodically evaluates the initiation of dividends. There is no assurance as to the amount or payment of dividends in the future because they will be subject to ongoing Board of Directors review and authorization will be based on a number of factors, including terms of our borrowing arrangements, business and market conditions, our future financial performance and other capital priorities.

The following table summarizes information about shares of common stock that were repurchased during the fourth quarter of 2020. 

regulatory requirements or restrictions, and other relevant factors. This amount does not include $16 thousand of stock repurchase related fees.

There were no repurchases related to warrants during the current quarter. Refer to Note 2 for information on warrants.

Not applicable.

In the first quarter of 2020, the COVID-19 virus was declared a pandemic by the World Health Organization. The COVID-19 pandemic has had negative impacts on our business, results of operations, financial condition and cash flows. A continued period of reduced demand for our products could have additional significant adverse consequences for us. The full extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on certain developments, including the duration and spread of the outbreak, its impact on our customers and suppliers and the range of governmental and community reactions to the pandemic, which are still uncertain and cannot be fully predicted at this time.

Our current view of the impacts of COVID-19 to our customers and suppliers is discussed below in the Market Overview section. Additionally, refer to Note 1 for further discussion of the COVID-19 pandemic impacts to our business and Note 8 for discussion of certain strategic actions announced during the second quarter of 2020 with respect to two of our thermal coal mining complexes in an effort to strengthen our financial performance.

All of our coal mining operations have been classified as essential in the states in which we operate. Health and safety are core values of our company and are the foundation for how we manage every aspect of our business and we have therefore implemented policies, procedures and prevention measures to protect our employees during the COVID-19 pandemic. These policies, procedures and prevention measures include, but are not limited to, employee communications on COVID-19 monitoring and precautionary measures, enhanced cleaning and sterilization practices, limiting contractor access to our properties, limiting business travel, implementing social distancing measures by staggering shift times, limiting in-person meetings and meeting sizes, and remote work arrangements. We will continue to evaluate these policies, procedures and precautionary measures for further enhancements as necessary.

We have not experienced significant supply chain disruptions due the COVID-19 pandemic.

We will continue to monitor these developments closely.

After a challenging COVID-19-afflicted 2020, the Australian metallurgical coal market, despite the recent pullback, has shown meaningful improvement in 2021, with the Australian premium hard coking coal index increasing 22% to $125 per metric ton in February since the end of 2020 and up nearly 30% since the lows of mid-November. The Atlantic High-Vol A indices have also performed well after reaching a low of $105 in mid-August. The current February High-Vol A index of $153 per metric ton represents a 46% improvement over that period.

Global manufacturing and industrial production are continuing to show growth in all regions with the manufacturing Purchasing Managers’ Indices (“PMI”) above 50.0 in the U.S., Europe, Brazil, India, and China, which is showing the most moderate growth among the major producers at 50.9 in January.

According to the World Steel Association (“WSA”), December 2020 crude steel production increased compared to the same prior year period in most producing regions. The overall global growth of 5.8% was driven mainly by China and Europe, which grew 7.7% and 10.2% in December, respectively. For the full year 2020, the global crude steel production declined less than 1%, led by declines in North America and Europe. South America, driven by Brazil, exhibited the strongest growth of any

major region, growing 16.3% in December. Turkey posted one of the most impressive growth rates in December and for the full year 2020, with crude steel production growing 17.7% and 6.0%, respectively.

We concluded our 2021 domestic metallurgical contracts during the fourth quarter. In total, we expect to sell approximately 14 million tons from our Met reportable segment in 2021. Coking coal prices have risen from their recent multi-year lows. Trade tensions between Australia and China forced Australian coal producers to sell at weaker prices and encouraged them to divert and re-sell cargoes away from China into other markets. These actions have opened the door for some North American coking coal producers to ship coal to China at higher netbacks than could be achieved in Atlantic Basin markets. In addition, we see demand improving in other Atlantic Basin and global markets. At this time, we are also seeing increasing spot interest from both domestic and seaborne customers and prospective customers which has resulted in an increase in shipments. In connection with the company’s strategic focus on optimizing metallurgical coal production, we continue striving to match our available products and production with customer demand.

On the thermal side, as of the end of December, natural gas prices had not achieved the previously forecasted levels. Since that time, severe weather has resulted in high consumer electricity demand and lower production, causing stress to the energy system in parts of the U.S. Natural gas inventories are poised to drop to the five-year average for the first time since the end of 2019. Central Appalachian thermal coal burns for our customers have not yet been significantly impacted by the fluctuations in natural gas prices, but we have seen increased demand associated with the recent severe weather. Internationally, Europe and Asia have also experienced severe weather, supply disruptions, reductions in coal capacity, and high carbon prices limiting opportunities for US coal. Increased ESG pressures are forcing expedited closure of coal units, domestically and abroad. US thermal coal producers are continuing to reduce investment in thermal coal. At our thermal coal operations, we have significantly reduced inventories at all locations, and are matching our sales and production to make for an orderly transition to lower thermal coal production.

As Alpha enters 2021, we continue to evaluate market conditions for our metallurgical coal products amid residual uncertainty attributable to the continued concern around the COVID-19 pandemic. The impact the pandemic may have on demand continues to make customer demand forecasts challenging. Depending on the extent and timing of global and national economic stabilization and recovery, our ability to estimate future customer coal demand remains limited.

We are a Tennessee-based mining company with operations across Virginia and West Virginia. With customers across the globe, high-quality reserves and significant port capacity, we are a leading U.S. supplier of metallurgical products for the steel industry. We operate high-quality, cost-competitive coal mines across the CAPP coal basin. As of December 31, 2020, our operations consisted of twenty-three active mines and eight coal preparation and load-out facilities, with approximately 3,250 employees. We produce, process, and sell met coal and thermal coal from operations located in Virginia and West Virginia. We also sell coal produced by others, some of which is processed and/or blended with coal produced from our mines prior to resale, with the remainder purchased for resale. As of December 31, 2020, we had 623.5 million tons of reserves, including 445.0 million tons of proven reserves and 178.5 million tons of probable reserves.

For the years ended December 31, 2020 and 2019, sales of met coal were 12.3 million tons and 12.7 million tons, respectively, and accounted for approximately 80% and 74%, respectively, of our coal sales volume. Sales of thermal coal were

3.2 million tons and 4.5 million tons, respectively, and accounted for approximately 20% and 26%, respectively, of our coal sales volume.

Our sales of met coal were made primarily to steel companies in the northeastern and midwestern regions of the United States and in several countries in Europe, Asia and the Americas. Our sales of thermal coal were made primarily to large utilities and industrial customers throughout the United States. For the years ended December 31, 2020 and 2019 approximately 64% and 61%, respectively, of our coal revenues were derived from coal sales made to customers outside the United States.

In addition, we generate other revenues from equipment sales, rentals, terminal and processing fees, coal and environmental analysis fees, royalties and the sale of natural gas. We also record freight and handling fulfillment revenue within coal revenues for freight and handling services provided in delivering coal to certain customers, which are a component of the contractual selling price.

Effective February 1, 2021, we changed our corporate name from Contura Energy, Inc. to Alpha Metallurgical Resources, Inc. for rebranding 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.

During the third quarter of 2020, we joined three other regional coal producers to restructure and expand the Virginia Coal & Energy Alliance to now be named the Metallurgical Coal Producers Association (“MCPA”) focusing on issues specific to the U.S.’s metallurgical coal industry. Additionally, the MCPA will focus on our regional presence by combining forces to advance collective interests.

We manage our commodity price risk for coal sales through the use of coal supply agreements. As of March 11, 2021, we have sales commitments as follows:

Due to the significant uncertainty in the worldwide coal markets due to COVID-19, there is risk of reduction in future shipments due to deferrals and utilization of force majeure clauses in customer contracts.

Our management strives to aggressively control costs and improve operating performance to mitigate external cost pressures. We experience volatility in operating costs related to fuel, explosives, steel, tires, contract services and healthcare, among others, and take measures to mitigate the increases in these costs at all operations. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. We may also experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems, and unexpected shortages of critical materials such as tires, fuel and explosives that may result in adverse cost increases and limit our ability to produce at forecasted levels.

Our results of operations for the years ended December 31, 2020 and 2019 are discussed in these “Results of Operations” presented below.

The following table summarizes information about our revenues during the years ended December 31, 2020 and 2019:

The following table summarizes information about our costs and expenses during the years ended December 31, 2020 and 2019:

The following table summarizes information about our other (expense) income during the year ended December 31, 2020 and 2019:

The following table summarizes information about our income tax benefit during the years ended December 31, 2020 and 2019:

Income tax benefit of $53.3 million was recorded for the year ended December 31, 2019 on a loss from continuing operations before income taxes of $272.9 million. The effective tax rate differs from the federal statutory rate of 21% primarily due to the impact of state income taxes, net of federal impact, the net operating loss carryback benefit, and the permanent impact of the percentage depletion deduction, mostly offset by the impact of the non-deductible goodwill impairment and the increase in the valuation allowance. Refer to Note 19 for additional information.

Our Met operations consist of high-quality met coal mines, including Deep Mine 41, Road Fork 52, Black Eagle, and Lynn Branch. The coal produced by Met operations is predominantly met coal with some amounts of thermal coal being produced as a byproduct of mining.

Our CAPP - Thermal operations consist of one underground thermal coal mine. The coal produced by CAPP - Thermal operations is predominantly thermal coal with some met coal byproduct.

Our All Other category is not included in our Coal Operations results of operations as it includes general corporate overhead and corporate assets and liabilities and the elimination of certain intercompany activity.

The discussion below contains “non-GAAP financial measures.” These are financial measures which either exclude or include amounts that are not excluded or included in the most directly comparable measures calculated and presented in accordance with generally accepted accounting principles in the United States (“U.S. GAAP” or “GAAP”). Specifically, we make use of the non-GAAP financial measures “Adjusted EBITDA,” “non-GAAP coal revenues,” “non-GAAP cost of coal sales,” and “Adjusted cost of produced coal sold.” We use Adjusted EBITDA to measure the operating performance of our segments and allocate resources to the segments. Adjusted EBITDA does not purport to be an alternative to net income (loss) as a measure of operating performance. We use non-GAAP coal revenues to present coal revenues generated, excluding freight and handling fulfillment revenues. Non-GAAP coal sales realization per ton for our operations is calculated as non-GAAP coal revenues divided by tons sold. We use non-GAAP cost of coal sales to adjust cost of coal sales to remove freight and handling costs, depreciation, depletion and amortization - production (excluding the depreciation, depletion and amortization related to selling, general and administrative functions), accretion on asset retirement obligations, amortization of acquired intangibles, net, idled and closed mine costs and coal inventory acquisition accounting impacts. Non-GAAP cost of coal sales per ton for our operations is calculated as non-GAAP cost of coal sales divided by tons sold. Non-GAAP coal margin per ton for our coal operations is calculated as non-GAAP coal sales realization per ton for our coal operations less non-GAAP cost of coal sales per ton for our coal operations. We also use Adjusted cost of produced coal sold to distinguish the cost of captive produced coal from the effects of purchased coal. The presentation of these measures should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP.

Management uses non-GAAP financial measures to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. The definition of these non-GAAP measures may be changed periodically by management to adjust for significant items important to an understanding of operating trends and to adjust for items that may not reflect the trend of future results by excluding transactions that are not indicative of our core operating performance. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Because not all companies use identical calculations, the presentations of these measures may not be comparable to other similarly titled measures of other companies and can differ significantly from company to company depending on long-term strategic decisions regarding capital structure, the tax jurisdictions in which companies operate, and capital investments.

Included below are reconciliations of non-GAAP financial measures to GAAP financial measures.

The following tables summarize certain financial information relating to our coal operations for the years ended December 31, 2020 and 2019: