What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2024-02-26 compared with 2023-02-23 · 145 added, 96 removed, 751 unchanged (24% of the section changed)

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We operate highly productive, cost-competitive coal mines across the CAPP coal basin.

Our portfolio of mining operations consists of 15 underground mines, nine surface mines and eight coal preparation plants.

Our portfolio of mining operations consists of 15 underground mines, seven surface mines and nine coal preparation plants.

We own a 65.0% interest in Dominion Terminal Associates (“DTA”), a coal export terminal in Newport News, Virginia.

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We predominantly produce metallurgical (“met”) coal, which is shipped to domestic and international steel and coke producers.

Although our strategic focus is on the production of met coal, we also produce thermal coal which is primarily sold to the domestic power generation industry.

Although our strategic focus is on the production of met coal, we also produce thermal coal as byproduct and it is primarily sold to large utilities and industrial customers both in the United States and across the world.

Refer to Notes 22 and 23 to the Consolidated Financial Statements for geographical information about our coal sales and additional segment information.

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Our reserve base consists of 303.0 million tons of proven and probable metallurgical reserves, and 12.9 million tons of proven and probable thermal reserves.

Additionally, we have approximately 527.3 million tons of in situ bituminous coal resources as of December 31, 2022.

Through our operations across the CAPP coal basin in Virginia and West Virginia, we are able to source coal from multiple mines to meet the needs of a long-standing global customer base, many of which have been served by us or our predecessors for decades.

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Other Business Developments

During the fourth quarter of 2022, in an effort to secure in-demand supplies and services, our subsidiary Maxxim Rebuild Co., LLC (“Maxxim”) purchased substantially all the assets of Industrial Plating and Machine, Inc.

(“IPM”), which manufactures essential mining equipment components, including gear cases.

Refer to Note 2 for additional information.

In addition, in January 2023, Maxxim completed a series of transactions to acquire a number of coal trucks and related equipment and facilities.

During 2023, development was completed and production began at our Rolling Thunder and Checkmate Powellton mines within our Power Mountain and Elk Run mining complexes, respectively, which produce High-Vol.

B quality met coal from the Powellton coal seam.

In August 2023, we completed our transition to a pure-play metallurgical producer with the closure of Slabcamp, which was our last remaining thermal mine.

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

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We assumed acquisition-related obligations through those settlement agreements, which became effective on July 26, 2016, the effective date of the Debtors’ Plan of Reorganization.

As of December 31, 2023, we did not have any remaining acquisition-related obligations.

Refer to Note 14 to the Consolidated Financial Statements for further information on our acquisition-related obligations.

On December 8, 2017, we closed a transaction with Blackjewel to sell our Western Mines located in the Powder River Basin (“PRB”), Wyoming, along with related coal reserves, equipment, infrastructure and other real properties.

On December 8, 2017, we closed a transaction with Blackjewel to sell our Western Mines located in the PRB, Wyoming, along with related coal reserves, equipment, infrastructure and other real properties.

On October 4, 2019, we closed on the ESM Transaction in connection with Blackjewel’s subsequent bankruptcy filing.

On May 29, 2020, certain of our subsidiaries (Contura Coal West, LLC and Contura Wyoming Land, LLC), one of which held the mining permits

for the Western Mines, were merged with certain subsidiaries of ESM to become wholly-owned subsidiaries of ESM and to complete the permit transfer process in connection with the ESM Transaction.

On May 29, 2020, certain of our subsidiaries

(Contura Coal West, LLC and Contura Wyoming Land, LLC), one of which held the mining permits for the Western Mines, were merged with certain subsidiaries of ESM to become wholly-owned subsidiaries of ESM and to complete the permit transfer process in connection with the ESM Transaction.

On November 9, 2018, we merged with Alpha Natural Resources Holdings, Inc.

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This transaction accelerated our strategic exit from thermal coal production to shift our focus to met coal production.

Our former NAPP operations results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements for the year ended December 31, 2020.

Refer to Note 3 to the Consolidated Financial Statements for further information on discontinued operations.

Effective February 1, 2021, we changed our corporate name from Contura Energy, Inc.

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Power Mountain WV 2016 2 CM NS 718 832 837 $ 70,594 —

Mammoth WV 2018 1 CM NS 843 1,238 1,490 $ 14,585 —

Elk Run WV 2018 1 CM CSX — — — $ 35,535 28,434

(1) Number of active mines as of December 31, 2023.

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Properties for further information.

Feasibility/Pre-feasibility studies are not considered cost beneficial for Power Mountain and Mammoth complexes.

Feasibility/Pre-feasibility study not considered cost beneficial for Power Mountain complex.

Aracoma – Aracoma is a mining complex located in Logan, Mingo, and Boone counties, West Virginia.

The complex has four active underground mines which produce primarily High-Vol.

The complex has three active underground mines which produce primarily High-Vol.

B quality met coal from the Upper Chilton, Upper Cedar Grove, and No.

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quality met coal from the Douglas coal seam.

The complex also has four active surface mines which produced High-Vol.

The complex also has three active surface mines which produced High-Vol.

A quality met coal as well as some thermal quality coal as a by-product of mining from multiple coal seams.

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Coal from the underground mine is processed at the Kingston Preparation Plant and trucked to the Pax Loadout to be loaded onto CSX rail for delivery to customers.

Coal from the surface mines may be processed through the Kingston Preparation Plant, trucked to and processed through the Mammoth Plant, or trucked directly to the Pax Loadout or Marmet Dock for delivery to customers.

Coal from the

surface mines may be processed through the Kingston Preparation Plant, trucked to and processed through the Mammoth Plant, or trucked directly to the Pax Loadout or Marmet Dock for delivery to customers.

Marfork – Marfork is a mining complex located in Raleigh, Boone, Kanawha, and Fayette counties, West Virginia.

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quality met coal from the Upper Banner, Lower Banner, and Jawbone coal seams.

The complex also has three active surface mines which produce primarily High-Vol.

The complex also has two active surface mines which produce primarily High-Vol.

A quality met coal as well as some thermal quality coal as a by-product of mining from multiple coal seams.

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B quality met coal from the Eagle coal seam.

In November 2022, we acquired additional property rights and coal resources and plan to develop a second underground mine which will produce High-Vol.

B quality met coal from the Powellton seam with production expected to commence in 2023.

Coal is processed at the Power Mountain Preparation Plant and loaded onto NS rail for delivery to customers.

Mammoth – Mammoth is a mining complex located in Kanawha and Fayette counties, West Virginia.

The complex has one active underground mine that produces thermal quality coal from the Stockton coal seam and is expected to mine out in 2023.

Coal is processed at the Mammoth Preparation Plant and loaded onto NS rail for delivery to customers.

In addition, during 2023 development was completed and production began at a second underground mine (with an estimated life of 15 years) which produces High-Vol.

B quality met coal from the Powellton coal seam.

Coal from the mine is currently trucked to and processed through the Mammoth Preparation Plant.

Following the expected development of a haul road in 2024, coal is expected to be trucked to and processed through the Power Mountain Preparation Plant.

Elk Run – Elk Run is a mining complex located in Boone County, West Virginia.

During 2023, development was completed and production began at an underground mine (with an estimated life of 22 years) which produces High-Vol.

B quality met coal from the Powellton coal seam.

Coal from the mine is processed at the Chess Processing Plant and loaded onto CSX rail for delivery to customers.

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

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Power Mountain 1985/2010 1,200 26% American Electric Power

Chess Processing (1)

1980/1998 2,200 N/A American Electric Power

Mammoth 1950/2008 1,200 18% American Electric Power

(1) Plant refurbished in 2023.

Produced tons received during the fourth quarter of 2023 but not processed until the first quarter of 2024.

The following is a summary of information regarding our active loadouts and docks as of December 31, 2023 :

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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.

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.

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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.

Our coal volumes include coal produced and processed by us, our “captive coal,” as well as coal purchased from third-party producers to blend with our produced coal in order to meet customer specifications.

These volumes are processed by us, meaning that we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale.

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Our export shipments serviced customers in 25 and 26 countries during the years ended December 31, 2023 and 2022, respectively.

Asia was our largest export market for the year ended December 31, 2022, with coal sales to Asia accounting for approximately 53% of export coal revenues and 43% of coal revenues.

Asia was also our largest export market for the year ended December 31, 2021, with coal sales to Asia accounting for approximately 49% of export coal revenues and 37% of coal revenues.

Asia was our largest export market for the years ended December 31, 2023 and 2022, with coal sales to Asia accounting for approximately 46% and 53%, respectively of export coal revenues and 34% and 43%, respectively, of coal revenues.

All of our sales are conducted in U.S.

Refer to Note 22 to the Consolidated Financial Statements for additional export coal revenue information.

Met coal accounted for approximately 95% and 92% of our coal revenues for the years ended December 31, 2022 and 2021, respectively.

Met coal accounted for approximately 95% of our coal revenues for each of the years ended December 31, 2023 and 2022.

Our met coal sales are typically made with customers with whom we have a long-term relationship.

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Volume for future years is generally contingent on both parties agreeing to a pricing mechanism to cover the contract year.

Thermal coal accounted for approximately 5% and 8% of our coal revenues for the years ended December 31, 2022 and 2021, respectively.

We often enter into long-term contracts with our thermal coal customers.

Thermal coal accounted for approximately 5% of our coal revenues for each of the years ended December 31, 2023 and 2022.

We sometimes enter into long-term contracts with our thermal coal customers.

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

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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.

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.

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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.

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 2022 and 2021, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation and Norfolk Southern Railway Company.

Rail shipments constituted approximately 84% and 82% of total shipments of coal volume from our mines during the years ended 2022 and 2021, respectively.

In the years ended December 31, 2023 and 2022, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation and Norfolk Southern Railway Company.

Rail shipments constituted approximately 89% and 84% of total shipments of coal volume from our mines during the years ended December 31, 2023 and 2022, respectively.

The balance was shipped from our preparation plants, loadout facilities or mines via truck or barge.

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Although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies, we believe that adequate substitute suppliers are available.

In December 2022, primarily to secure the supply of certain underground mining equipment parts needed for our operations, we purchased substantially all of the assets of a mining equipment component manufacturing and rebuilding business.

Refer to Note 2 for additional information.

In the first quarter of 2023, we completed a series of transactions to acquire a number of coal trucks and related equipment and facilities to secure trucking services for our operations.

In December 2022, we purchased substantially all of the assets of a mining equipment component manufacturing and rebuild business to help secure the supply of certain underground mining equipment parts needed for our operations.

We incur substantial expenses each year to procure goods and services in support of our respective business activities in addition to capital expenditures.

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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.

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 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.

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Approximately 97% of our total workforce was union-free as of December 31, 2023.

Certain of our subsidiaries have wage agreements with the United Mine Workers of America (“UMWA”) representing roughly 3% of our workforce.

Certain of our subsidiaries have wage agreements with the UMWA representing roughly 3% of our workforce.

Certain of our subsidiaries have wage agreements with the UMWA that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2025 and one on February 28, 2026.

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and a 401(k) retirement savings program with an employer match.

All employees have access to our Employee Assistance Program (“EAP”) at no cost, which gives them and their family access to licensed professionals for help with mental health, stress, addiction, grievances, relationship issues, childcare and eldercare services, legal and personal finance services and other work/life balance matters.

To help retain key employees in certain positions, our long-term incentive program awards cash or equity grants with time-based and performance-based vesting conditions.

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Employee Training and Development

At Alpha, we strive to maintain a diverse and inclusive workforce and a positive culture where employees can contribute their best work, take pride in doing the right thing, and work to improve and strengthen the organization.

At Alpha, we strive to maintain a positive culture where employees can contribute their best work, take pride in doing the right thing, and work to improve and strengthen the organization.

To have a successful operation, we endeavor to establish and maintain relationships with and among our employees that are built upon mutual respect, trust, and appreciation.

Due to the industry shortage of skilled and experienced employees, we have an extensive in-house apprentice miner training program.

Selected participants are given robust safety and mining training over a six-month period in order to obtain their required miner’s certification.

We frequently provide training opportunities for operations employees to obtain certifications for Emergency Medical Technician (“EMT”), Mechanical Engineering Technology (“MET”), foreman and supervisory certifications, and electrical certifications in addition to providing apprentice miner training and supervisor training programs.

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Our employees are empowered with the skills, training, resources, and responsibility to perform their jobs in a safe manner and are accountable for their own safety as well as the safety of their co-workers.

Every employee has a voice in the safety process at each of our mines and other operating sites.

Every employee has a voice in the safety process at each of our mines

and other operating sites.

Our behavior-based safety process empowers employees to engage in the elimination of at-risk behaviors in the workplace and in incident prevention and continuous improvement.

In recognition of the interdependence

between safety and operations, our “Safe Production” process promotes the effective utilization of procedures, developing safety action plans at each operating group and sharing of best practices, safety alerts and lessons learned across the entire organization.

In recognition of the interdependence between safety and operations, our “Safe Production” process promotes the effective utilization of procedures, developing safety action plans at each operating group and sharing of best practices, safety alerts and lessons learned across the entire organization.

Safety leadership and training programs are based upon the concepts of situational awareness and observation, changing behaviors and, most importantly, employee involvement.

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As posted on our Company website, several of our mine operations have been recognized on numerous occasions for outstanding performance and have received several awards in the areas of safety and mine rescue.

In 2022, Alpha mine rescue teams won a national championship along with several other first-place awards in both overall competition honors and technical category titles.

In 2023, Alpha mine rescue teams won two overall grand champion awards along with several other first-place awards in both overall competition honors and technical category titles.

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

In the first quarter of 2020, the COVID-19 virus was declared a pandemic by the World Health Organization.

In response to the COVID-19 pandemic, we implemented policies, procedures, and prevention measures to protect the safety and health of our employees.

During 2021, our Company experienced an increase in employee absences due to COVID-19-related matters such as precautionary quarantining, waiting on COVID-19 test results, testing positive for COVID-19, receiving a vaccination, or providing care for a family member.

The number of employee absences related to COVID-19 decreased in 2022 and was limited in its impact.

We will continue to evaluate our policies, procedures, and precautionary measures in light of further developments as necessary or appropriate.

Legal Proceedings

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We record accruals based on an estimate of the ultimate outcome of these matters, but these estimates can be difficult to determine and involve significant judgment.

For additional information about the Company’s legal proceedings, refer to Note 21 , part (d), to the Consolidated Financial Statements, which is incorporated herein by reference.

ENVIRONMENTAL AND OTHER REGULATORY MATTERS

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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 U.S.

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As the mine permit transfer process relating to our sale of the Western Assets to Blackjewel had not been completed prior to Blackjewel’s and certain of its affiliates’ filing petitions for relief under chapter 11 of title 11 of the U.S.

Code (the “Bankruptcy Code”), we remained the permitholder in good standing for both mines.

In connection with ESM’s acquisition of the Western Assets from Blackjewel, on October 18, 2019, we and ESM

finalized an agreement that provided, among other items, for the eventual transfer of the Western Asset permits from us to ESM and replacement by ESM of our surety bonds associated with these properties.

Code (the “Bankruptcy Code”), we remained the permitholder in good standing for both

In connection with ESM’s acquisition of the Western Assets from Blackjewel, on October 18, 2019, we and ESM finalized an agreement that provided, among other items, for the eventual transfer of the Western Asset permits from us to ESM and replacement by ESM of our surety bonds associated with these properties.

In furtherance of certain objectives contemplated under that agreement, we and ESM agreed to the merger of two of our now-former subsidiaries, i.e.

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Public notice of the proposed permit is given, which also provides for a comment period before a permit can be issued.

Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take months or even years to be issued.

Regulatory authorities have considerable discretion in the timing of the permit issuance

and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may

take months or even years to be issued.

Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced.

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The current fee, which is effective through September 30, 2034, is $0.224 per ton on surface-mined coal and $0.096 per ton on deep-mined coal.

The previous fee, which was effective through September 30, 2021, was $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal.

For the years ended December 31, 2022 and 2021, we recorded $2.0 million and $2.5 million, respectively, of expense related to these fees.

For each of the years ended December 31, 2023 and 2022, we recorded $2.0 million of expense related to these fees.

While SMCRA is a comprehensive statute, SMCRA does not supersede the need for compliance with other major environmental statutes, including the Endangered Species Act;

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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.

Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to particulate matter (“PM”), which may include controlling fugitive dust.

The Clean Air Act indirectly affects coal mining operations by extensively regulating air emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants or the use of met coal in connection with steelmaking operations.

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On December 7, 2020, the EPA announced the agency’s final

decision to retain the existing National Ambient Air Quality Standards for particulate matter (PM) set by the Obama-Biden Administrations without changes.

In October 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard.

decision to retain the existing National Ambient Air Quality Standards for particulate matter set by the Obama-Biden Administrations without changes.

However, on January 6, 2023, the EPA proposed to revise the primary (health-based) annual standard for PM2.5, from its current level of 12.0 parts per billion (ppb or µg/m3) to within the range of 9.0 to 10.0 µg/m3.

The EPA also proposed revisions to some other provisions of the PM NAAQS, including revisions to the air quality index and monitoring requirements, but did not propose to change other key aspects of the standard:

(i) the secondary (welfare-based) annual PM2.5 standard;

(ii) the primary and secondary 24-hour PM2.5 standards and (iii) the primary and secondary 24-hour PM10 standards.

On February 7, 2024, the EPA revised the primary (health-based) annual standard for PM2.5, from its current level of 12.0 µg/m3 to 9.0 µg/m3.

The EPA retained the 24-hour standard and the current primary 24-hour standard for PM10, which provides protection against coarse particles.

The EPA is not changing the secondary (welfare-based) standards for fine particles and coarse particles at this time.

In October 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 ppb from the previous 75 ppb standard.

The EPA made the majority of area designations related to this rule on November 16, 2017 and June 4, 2018 and finalized designations for the remaining regions of the country on July 25, 2018.

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

A suit by industry challenging the EPA’s 2015 Ozone NAAQS ( Murray Energy Corp.

EPA) is currently pending in the D.C.

In April 2017, the D.C.

Circuit Court granted the EPA’s motion to indefinitely delay any decision on the challenges pending the EPA’s possible reconsideration of the rule.

In July 2018, the D.C.

Circuit Court returned the matter to its active docket and in August 2018, the EPA indicated to the court that it would not be revising the 2015 standards at this time.

In August 2019, the D.C.

Circuit upheld the rule with the exception of the secondary NAAQS standards addressing protection of animals, crops and vegetation, which were sent back to the EPA for further consideration.

A suit by industry in the D.C.

Circuit challenged the EPA’s 2015 Ozone NAAQS (Murray Energy Corp.

EPA), which resulted in the court upholding the rule with the exception of the secondary NAAQS standards addressing protection of animals, crops and vegetation, which were sent back to the EPA for further consideration.

On December 23, 2020, the EPA announced its decision to retain, without changes, the 2015 ozone National Ambient Air Quality Standards set by the Obama-Biden Administration.

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On February 26, 2019, the EPA published a final rule amending the NOx SIP Call regulations to allow states to establish alternative monitoring and reporting requirements for certain sources.

On March 15, 2023, the EPA issued its Good Neighbor Plan rules (the “Good Neighbor Plan”), which secure significant reductions in cross-state air pollution of ozone-forming emissions of nitrogen oxides (NOx) from power plants and industrial facilities.

The Good Neighbor Plan is intended to reduce seasonal ozone-forming emissions of NOx from power plants and industrial facilities in 23 states.

Industry groups and the State of Ohio have filed lawsuits challenging the Good Neighbor Plan.

Due to court orders staying implementation of certain aspect of the Good Neighbor Plan, the EPA is implementing the Good Neighbor Plan only in certain states.

As of September 21, 2023, the Good Neighbor Plan's “Group 3” ozone-season NOx control program for power plants is being implemented in the following states:

Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and Wisconsin.

Due to the court orders, the EPA is not currently implementing the Good Neighbor Plan “Group 3” ozone-season NOx control program for power plants in the following states:

Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and West Virginia.

On December 20, 2023, the United States Supreme Court agreed to hear oral argument in four consolidated cases challenging the Good Neighbor Plan.

The Court has scheduled oral argument for the cases in its February 2024 term and directed the parties to address, among other issues, whether the emissions controls imposed by the Good Neighbor Plan are reasonable regardless of the number of states subject to the Good Neighbor Plan.

• Cross-State Air Pollution Rule.

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The EPA estimated that the Revised CSAPR Update rule will reduce NOX emissions from power plants in 12 states in the eastern United States by 17,000 tons in 2021 compared to projections without the rule, yielding public health and climate benefits that are valued, on average, at up to $2.8 billion each year from 2021 to 2040.

An industry group has challenged the Revised CSAPR Update rule in the U.S.

An industry group challenged the Revised CSAPR Update rule in the U.S.

Court of Appeals for the District of Columbia.

The Court heard oral arguments on September 28, 2022.

However, the Revised CSAPR Update rule remains in effect during the pendency of the appeal.

The Revised CSAPR Update rule and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants, in addition to the significant number of plants and units that have already been retired as a result of environmental and regulatory requirements and uncertainties adversely impacting coal-fired generation.

Such retirements would likely adversely impact our business.

On March 3, 2023, the Court rejected this challenge.

• Mercury and Hazardous Air Pollutants.

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The EPA states, “emissions of HAP have been reduced such that residual risk is at acceptable levels, that there are no developments in HAP emissions controls to achieve further cost-effective reductions beyond the current standard, and, therefore, no changes to the MATS rule are warranted.”

On February 15, 2023, however, the EPA revoked its 2020 finding that it was not appropriate and necessary to regulate coal- and oil-fired power plants under Section 112 of the Clean Air Act, which regulates HAP emissions.

The EPA reviewed the 2020 finding and stated that it considered updated information on both (i) the public health burden associated with HAP emissions from coal- and oil-fired power plants;

and (ii) the costs associated with reducing those emissions under the MATS rule.

On April 3, 2023, the EPA issued a proposed rule that the EPA said would strengthen and update the MATS for power plants to reflect recent developments in control technologies and the performance of these plants.

Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed.

Regulation of mercury emissions by the EPA (and in particular, the reconsideration by the current EPA of any rulemaking relating to the MATS rule during the prior presidential administration), states, Congress, or pursuant to an international treaty may further decrease the demand for coal.

Regulation of mercury emissions by the EPA (and in particular, the reconsideration by the current EPA of

any rulemaking relating to the MATS rule during the prior presidential administration), states, Congress, or pursuant to an international treaty may further decrease the demand for coal.

Like CSAPR, MATS and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants, in addition to the significant number of plants and units that have already been retired as a result of environmental and regulatory requirements and uncertainties adversely impacting coal-fired generation.

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On June 1, 2017, the Trump administration announced that the U.S.

will withdraw from the Paris Agreement.

would withdraw from the Paris Agreement.

This withdrawal formally took effect on November 4, 2020.

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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.

The Glasgow Climate Pact reached at the 2021 United Nations Climate Change Conference (COP26), though not legally binding, contains a plan to reduce use of coal by 40%.

The COP28 United Nations Climate Change Conference was held in Dubai, the United Arab Emirates, held from November 30 to December 13, 2023.

COP28 was intended to evaluate the world’s efforts to address climate change under the Paris Agreement.

At the end of the COP28 conference, the participating countries agreed to a call on

governments worldwide to speed up the transition away from fossil fuels to renewables such as wind and solar power.

These commitments and agreements could further reduce demand and prices for our coal.

In 2009, the EPA issued a finding that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment.

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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.

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).

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In addition, various states and regions have adopted initiatives to reduce, and in some cases phase out, GHG emissions and certain governmental bodies, including the states of Virginia and California, have considered or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities.

A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power.

A number of states have enacted legislative

mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power.

For example, on September 10, 2018, California adopted a law that requires all electricity consumed by the state to be generated from renewable sources such as solar, wind and hydropower by 2045.

On October 7, 2023, California Governor Gavin Newsom signed three landmark climate disclosure bills that are more stringent than the proposed SEC rules.

California’s group of new laws address (i) GHG emissions reporting in compliance with the Greenhouse Gas Protocol (“GHG Protocol”), (ii) climate-related financial risk reporting in accordance with the recommendations of the Task Force on Climate-Related Financial Disclosures (“TCFD”), and (iii) disclosure of information about certain emissions claims and the sale and use of carbon offsets.

Although the SEC’s climate disclosure proposal includes GHG Protocol and TCFD requirements, unlike the SEC’s proposed rule, the California requirements apply to certain private and public companies with business activities in California.

AB 1305 addresses voluntary carbon market disclosures.

It applies to entities that (i) operate and make emissions claims within California;

or (ii) buy or sell carbon offsets within California.

SB 253 is the Climate Corporate Data Accountability Act.

It applies only to business entities with annual revenue over $1 billion that do business in California.

It requires disclosure of scope 1, scope 2, and scope 3 GHG emissions.

Annual reporting of scope 1 and scope 2 GHC emissions will be required for covered entities beginning in 2026 (for the 2025 fiscal year).

Annual reporting of scope 3 GHG emissions will be required beginning in 2027.

SB 261 addresses climate-related financial risks of greenhouse gases.

It applies to business entities that do business in California if their annual revenue exceeds $500 million.

Disclosure will be required on or before January 1, 2026 and biennially thereafter.

The Company currently does not do business in California.

In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely affect the future global demand for coal.

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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.

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.

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On January 18, 2023, the rule was published in the Federal Register.

The rule will be effective on March 20, 2023.

Like the NWPR, the Revised Definition of Waters of the United States rule is likely to be the subject of legal challenges and its ultimate impact on our operations is uncertain.

The rule was effective on March 20, 2023.

Like the NWPR, the Revised Definition of Waters of the United States rule has been the subject of legal challenges.

On May 25, 2023, the U.S.

Supreme Court’s decision in Sackett v.

EPA limited the jurisdiction of the EPA and the COE over wetlands.

While the January 18, 2023 rule was not directly before the Court, the Court considered the jurisdictional standards set forth in the rule.

In Sackett, the Court held that the Clean Water Act’s use of “waters” encompasses only those relatively permanent, standing or continuously flowing bodies of water forming geographical features that are described in ordinary parlance as streams, oceans, rivers, and lakes.

On August 29, 2023, the EPA and the COE issued a final rule to amend the January 2023 rule, to conform the definition of “waters of the United States” to the Supreme Court’s decision in Sackett.

This conforming rule amends the provisions of the January 18, 2023 definition of “waters of the United States” that are invalid under the Supreme Court’s interpretation of the Clean Water Act in the Sackett decision.

The final amended conforming rule became effective on September 8, 2023.

Its ultimate impact on our operations remains uncertain until the agencies regularly implement and apply the rule.

Cooling Water Intake

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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.

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.

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.

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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.

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.

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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.

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.

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In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air.

Additionally, MSHA’s proposed rule, Lowering Miners’ Exposure to Respirable Crystalline Silica and Improving Respiratory Protection, was published in the federal register on July 13, 2023.

The proposed rule would set the permissible exposure limit of respirable crystalline silica at 50 micrograms per cubic meter of air (µg/m3) for a full shift exposure, calculated as an 8-hour time weighted average, for all miners.

The proposal also includes other requirements to protect miner health and update existing respiratory protection requirements.

The written comment period on the proposed rule was originally scheduled to end on August 28, 2023, and was later extended to September 11, 2023.

MSHA held three public hearings to give stakeholders the opportunity to present testimony, written comments, and other documentary evidence on the proposed rule.

The final rule is anticipated to be published in 2024.

Our compliance with these or any other new mine health and safety regulations could increase our mining costs.

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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.

During 2021, the trust fund was funded by an excise tax on coal sold of $1.10 per ton for deep-mined coal and $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

Effective January 1, 2022, the trust fund was funded by an excise tax on coal sold of $0.50 per ton for deep-mined coal and $0.25 per ton for surface-mined coal, neither amount to exceed 2% of the gross sales price.

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The proposed rule would also clarify acceptable forms of security and establish an appeals process.

Comments on the proposed rule are due no later than March 20, 2023.

Comments on the proposed rule were originally due no later than March 20, 2023.

The Department of Labor subsequently extended the deadline for comments until April 19, 2023, and has not yet issued a final rule.

Coal Industry Retiree Health Benefit Act of 1992

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Bituminous coal.

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

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

British Thermal Unit or BTU.

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

Cumberland Back-to-Back Coal Supply Agreement.

Certain agreements with Iron Senergy under which Iron Senergy would sell to the Company all of the coal that the Company was obligated to sell to customers under Cumberland coal supply agreements (“Cumberland CSAs”) which existed as of the transaction closing date but did not transfer to Iron Senergy at closing (each, a “Cumberland Back-to-Back Coal Supply Agreement”).

Each Cumberland Back-to-Back Coal Supply Agreement had economic terms identical to, but offsetting, the related Cumberland CSA.

If a Cumberland customer subsequently consented to assign a Cumberland CSA to Iron Senergy after closing, the related Cumberland CSA would immediately and automatically transfer to Iron Senergy and the related Cumberland Back-to-Back Coal Supply Agreements executed by the parties would thereupon terminate as set forth therein.

Development stage property.

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the overhead surface of a coal working place.

One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned.

Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Surface mine.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business