What changed in this filing

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Item 1. Business

2022-04-01 compared with 2021-02-18 · 209 added, 208 removed, 314 unchanged (57% of the section changed)

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Our common stock is listed on the NASDAQ Global Select Market under the symbol “METC”.

Our 9.00% Senior Notes due 2026 (the “Senior Notes”) are listed on the NASDAQ Global Select Market under the symbol “METCL”.

Our principal corporate offices are located in Lexington, Kentucky.

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We are an operator and developer of high-quality, low-cost metallurgical coal in southern West Virginia, southwestern Virginia, and southwestern Pennsylvania.

We are a pure play metallurgical coal company with 262 million tons of high-quality metallurgical coal reserves.

We are a pure play metallurgical coal company with 39 million reserve tons and 769 million resource tons of high-quality metallurgical coal.

We believe our advantaged reserve geology provides us with higher productivities and industry leading lower cash costs.

Our development portfolio primarily includes four properties:

Elk Creek, Berwind, RAM Mine and Knox Creek.

We believe each of these properties possesses geologic and logistical advantages that make our coal among the lowest delivered-cost U.S.

metallurgical coal to a majority of our domestic target customer base, North American blast furnace steel mills and coke plants, as well as international metallurgical coal consumers.

We operate three deep mines and a surface mine at our Elk Creek mining complex.

Elk Creek, Berwind, Knox Creek and RAM Mine.

Each of these properties possesses geologic and logistical advantages that make our coal among the lowest delivered-cost U.S.

metallurgical coal to our domestic target customer base, North American blast furnace steel mills and coke plants, as well as international metallurgical coal consumers.

Our operations include three deep mines and a surface mine at our Elk Creek mining complex (the “Elk Creek Complex”).

Development of this complex commenced in 2016 and included construction of a preparation plant and rail load-out facilities.

The Elk Creek property consists of approximately 20,166 acres of controlled mineral rights and contains 25 seams that we have targeted for production.

Development of our Berwind mining complex began in late 2017.

In 2020, we suspended development at the Berwind mining complex due to lower pricing and demand largely caused by the novel coronavirus disease 2019 (“COVID-19”) outbreak.

This complex remains a key part of our anticipated future growth.

We expect to achieve commercial production at the Berwind mining complex approximately six months after we resume the slope project as described under “Our Projects – Berwind” below.

The Elk Creek property consists of approximately 20,200 acres of controlled mineral rights and contains approximately 16 seams that we have targeted for production.

Development of our Berwind mining complex (the “Berwind Complex”) began in late-2017.

In 2020, we suspended development at the Berwind Complex due to lower pricing and demand largely caused by the COVID-19 outbreak.

In early-2021, as pricing and demand improved, Berwind development was restarted.

We successfully reached the thicker Pocahontas No.

4 seam in late-2021.

The Berwind property consists of approximately 41,300 acres of controlled mineral rights.

In December 2021, we acquired what are referred to as the “Amonate Assets” from subsidiaries of Coronado Global Resources Inc.

(“Coronado”) as described under “Our Projects – Berwind” below.

The Amonate Assets include a processing plant located in our Berwind Complex, saving us transportation costs to our Knox Creek plant 26 miles away.

We expect to incur approximately $10 million of capital expenditures in 2022 to bring the newly acquired plant at the Berwind Complex online.

Our Knox Creek facility includes a preparation plant and 62,100 acres of controlled mineral rights that we expect to develop in the future.

The Knox Creek preparation plant processes coal from our Berwind mine as well as coal we may purchase from third parties.

Our RAM Mine property is located in southwestern Pennsylvania, consists of approximately 1,570 acres of controlled mineral rights, and is scheduled for initial production after a mining permit is issued.

We expect this permit to be issued in 2021.

The Knox Creek preparation plant processes coal from our Berwind Complex (until the newly acquired plant at the Berwind Complex is placed into operation) as well as coal we may purchase from third parties.

Our RAM Mine property is located in southwestern Pennsylvania, consists of approximately 1,567 acres of controlled mineral rights, and is scheduled for initial production after a mining permit is issued and market conditions warrant development.

As of December 31, 2021, our estimated aggregate annual production capacity is approximately 2.4 million clean tons of coal.

We plan to complete development of our existing properties and increase production from our existing development portfolio to more than 4-4.5 million clean tons of metallurgical coal annually, subject to market conditions, permitting and additional capital deployment.

We plan to complete development of our existing properties and increase production from our existing development portfolio to approximately 5 million clean tons of metallurgical coal annually, subject to market conditions, permitting and additional capital deployment.

We may also acquire additional reserves or infrastructure that contribute to our focus on advantaged geology and lower costs.

Metallurgical Coal Industry

Metallurgical coal is also known as “coking coal,” and is a key component of the blast furnace steelmaking process.

North American metallurgical mines are primarily located in the Appalachian area of the eastern United States, and supply all of the requirements of the steel industry.

Imported metallurgical coal has historically been un-economic due to transportation costs.

Supply in excess of what can be consumed in North America is exported to the seaborne market to buyers in Europe, South America, Africa, India and Asia.

Metallurgical coal is transported by truck, rail and barge to coke batteries.

Metallurgical coal contracts in North America frequently are calendar year contracts where both prices and volumes are fixed in the third or fourth quarter for the following calendar year.

The United States is the second largest global supplier to the seaborne metallurgical coal market behind Australia.

producers, with their variable production volumes, generally serve as a swing supplier to the international metallurgical coal market.

metallurgical coal exports compete with Australian metallurgical coals that are generally produced at lower cost, but are geographically disadvantaged to supply Western Europe.

Conversely, Australian production has a much shorter logistical route to East Asian customers.

Metallurgical coal is also known as “met coal “ or “coking coal,” and is a key component of the blast furnace steelmaking process.

United States metallurgical coal mines are primarily located in the Appalachian area of the eastern U.S.

Imported metallurgical coal has historically been uneconomic due to transportation costs and availability of domestic supply.

Metallurgical coal is transported to domestic customers by truck, rail, barge and vessel.

Metallurgical coal contracts in North America are typically 12-month, calendar year contracts where both prices and volumes are fixed.

These contracts are normally negotiated and settled during the third and fourth quarters of the preceding calendar year.

metallurgical coal supply in excess of what can be consumed in North America is exported to the seaborne market and sold to buyers in Europe, South America, Africa, India and Asia.

is the second largest global supplier to the seaborne metallurgical coal market behind Australia.

metallurgical coal exports are primarily sold to buyers in the Atlantic Basin market (customers in Europe, Brazil and Africa), and serve as swing supply to buyers in the Pacific Basin (customers in India, South Korea, Japan and China).

metallurgical coal exports compete with Australian metallurgical coals that are generally produced at a lower cost, but are geographically disadvantaged to the Atlantic Basin.

Conversely, Australian production has a much shorter logistical route to Pacific Basin customers.

Any supply shortfall out of Australia, or increase in global demand beyond Australia’s capacity, has historically been serviced by U.S.

coal producers.

and Canadian metallurgical coal producers.

Export metallurgical coal pricing is determined utilizing a series of indices from a number of independent sources and is adjusted for coal quality.

Contracted volumes have terms that vary in duration from spot to one year, rarely exceeding one year.

In some cases, indices are used at the point that the coal changes hands.

In other cases, an average over time may be utilized.

When the term “benchmark” is still utilized, it too is determined based on index values, typically for the preceding three months.

Metallurgical coals are generally classified as high, medium or low volatile.

Contracted export volumes have terms that vary in duration from spot cargoes to one year, rarely exceeding one year.

In some cases, indices are used to calculate pricing at the point that the coal changes hands.

In other cases, an average value of indices over time may be utilized.

While the term “benchmark” is still utilized, it too is determined based on index values, typically for the preceding three months.

Metallurgical coals are generally classified as high, medium or low-volatile (“vol”).

Volatiles are products, other than water, that are released as gas or vapor when coal is converted to coke.

Carbon is what remains when the volatiles are released.

Our business strategy is to increase stockholder value through sustained earnings growth and cash flow generation by:

Carbon is the primary element which remains when the volatiles are released.

Our business strategy is to increase stockholder value through sustained earnings growth, cash flow generation and dividends by:

Developing and Operating Our Metallurgical Coal Properties.

We have a 262 million ton reserve base of high-quality metallurgical coal with attractive quality characteristics across high-volatility and low-volatility segments.

This geologically advantaged reserve base allows for flexible capital spending in challenging market conditions.

permitting and additional capital deployment.

We have 39 million and 769 million tons of high-quality metallurgical coal reserves and resources, respectively, with attractive quality characteristics across high-volatility and low-volatility segments.

This geologically advantaged resource and reserve base allows for flexible capital spending in challenging market conditions.

We plan to complete development of our existing properties and increase production from our existing development portfolio to approximately 5 million clean tons of metallurgical coal, subject to market conditions, permitting and additional capital deployment.

We may also acquire additional reserves or infrastructure that contribute to our focus on advantaged geology and lower costs.

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Elk Creek Mining Complex

Our Elk Creek mining complex in southern West Virginia began production in late December 2016.

Our Elk Creek Complex in southern West Virginia began production in late December 2016.

The Elk Creek property consists of approximately 20,200 acres of controlled mineral and contains 16 seams that we believe are economically mineable.

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We control the majority of the coal and related mining rights within the existing permitted areas and our current mine plans, as well as the surface for our surface facilities, through leases and subleases from Ramaco Coal, LLC, a related party, and McDonald Land Company.

We estimate that the Elk Creek mining complex contains reserves capable of yielding approximately 113 million tons of clean saleable metallurgical coal.

We currently market most of the coal produced from the Elk Creek mining complex as a blended high volatile A/B product.

We estimate that the Elk Creek Complex contains reserves capable of yielding approximately 29 million tons of clean saleable metallurgical coal and 223 million tons of high-quality metallurgical coal resources.

We expect many of the coal resources will be converted to reserves when further drilling and exploration is completed on the property.

We currently market most of the coal produced from the Elk Creek Complex as a blended high-volatile A/B product.

When segregated, a portion of our coal can be sold as a high-volatile A product for a premium.

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We have not yet committed the capital for development of a Norfolk Southern rail facility.

The existing impoundment at Elk Creek has been converted principally into a combined refuse facility.

The combined capacity is expected to provide approximately 20 years of disposal life for our operations.

We completed construction of a full complement of plate presses during 2020 to allow for dewatering material currently being pumped to our impoundment.

This equipment allows us to process all waste material for placement in the combined refuse facility.

On November 5, 2018, one of our three raw coal storage silos that fed our Elk Creek plant experienced a partial structural failure.

A temporary conveying system completed in late-November 2018 restored approximately 80% of our plant capacity.

We completed a permanent belt workaround and restored the preparation plant to its full processing capacity in mid-2019.

Our insurance carrier, Federal Insurance Company, disputed our claim for coverage based on certain exclusions to the applicable policy and, therefore, on August 21, 2019 we filed suit against Federal Insurance Company and Chubb INA Holdings, Inc.

in Logan County Circuit Court in West Virginia seeking a declaratory judgment that the partial silo collapse was an insurable event and to require coverage under our policy.

Defendants removed the case to the United States District Court for the Southern District of West Virginia, and upon removal, we substituted ACE American Insurance Company as a defendant in place of Chubb INA Holdings, Inc.

Currently, the case is scheduled for trial beginning June 29, 2021, in Charleston, West Virginia.

The combined refuse capacity at the active disposal areas is expected to provide approximately 12 years of disposal life for our operations.

We completed construction of a full complement of plate presses during 2020 to allow for dewatering material which then was being pumped as slurry to our impoundment.

This equipment allows us to process all waste material for placement in areas designed for combined refuse disposal and maximize the life for disposal of fine waste rock in the pool of the impoundment.

A large portion of our controlled reserves are permitted through existing, issued permits.

We currently have three mining permits that have not been activated and we are actively pursuing multiple new permits.

We currently have seven planned and permitted mines within the Elk Creek Complex and three permitted inactive mines.

We are actively pursuing multiple new permits.

On January 3, 2020, we entered into a mineral lease with the McDonald Land Company for coal reserves which, in many cases, are located immediately adjacent to our Elk Creek Complex.

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While it is unusual to have a metallurgical reserve in this part of Central Appalachia remain idle for such an extended period of time, the configuration and location of the tracts lend themselves to be mined and processed far more efficiently from our Elk Creek property.

The McDonald reserves are expected to have the same geologic advantages and low costs that are being experienced in our Elk Creek mines.

Our 2020 reserve study of the McDonald tracts showed over 21 million proven and probable reserves in approximately 20 different coal seams to our Elk Creek reserve base.

We project to mine approximately 10 million tons of these reserves in our current 10 year mine plan.

The McDonald reserves have the same geologic advantages and low costs that are being experienced in our Elk Creek mines.

During 2022, we plan to begin work on a throughput upgrade at our Elk Creek Preparation plant.

We expect this upgrade will raise the nameplate processing capacity to 1,000 raw tons per hour and our approximate annual clean capacity from this complex to 2.5 million tons per year.

We expect that this upgrade will be completed in 2023.

In order to meet this increased capacity, we have also begun development work on additional high-quality, low-cost, high- volatile underground and surface mines at Elk Creek.

These mines will begin production during 2022 and reach full levels of productivity during 2023 to align with the preparation plant upgrade.

Berwind Mining Complex

Our Berwind mining complex is located on the border of West Virginia and Virginia and is well-positioned to fill the anticipated market for low volatile coals.

The Berwind property consists of approximately 31,200 acres of controlled mineral and contains a large area of Squire Jim seam coal deposits.

The Squire Jim seam of coal is the lowest known coal seam on the geologic column in this region, and due to depth of cover has never been significantly explored.

We have outcrop access to this seam at the top of an anticline.

Should we choose to develop this seam in the future, we expect to experience above average seam height.

Development of our Berwind mining complex began in late 2017 in the thinner Pocahontas No.

Our Berwind Complex is located on the border of West Virginia and Virginia and is well-positioned to fill the anticipated market for low-volatile coals.

The Berwind property consists of approximately 41,300 acres of controlled mineral, excluding the Amonate acquisition.

Development of our Berwind Complex began in late-2017 in the thinner Pocahontas No.

3 seam with plans to slope up into the thicker Pocahontas No.

4 seam, subject to market conditions.

In 2020, we suspended development at the Berwind mining complex due to lower pricing and demand largely caused by the economic effects of COVID-19.

This complex remains a key part of our anticipated future growth.

We expect to achieve commercial production at the Berwind mining complex approximately six months after we resume the slope project.

We estimate that the mine life for the Berwind mining complex is more than 20 years.

In February 2021, the resumption of the slope development project at Berwind was approved by our Board of Directors in anticipation of better market conditions.

In 2020, we suspended development at the Berwind Complex due to lower pricing and demand largely caused by the economic effects of COVID-19.

In early-2021, as pricing and demand improved, Berwind development resumed.

We successfully reached the Pocahontas No.

4 seam in late-2021 and expect to ramp up to full production levels during the second quarter of 2022.

We view Berwind as the second flagship complex for Ramaco.

The slope project will allow us to transition our mining efforts at Berwind to the thicker Pocahontas No.

We have already expended more than $50 million in growth capital during the past four years in development at the Berwind mining complex.

We anticipate spending another $10-12 million in growth capital over the next 12 months with approximately one-third of that outlay occurring in early 2022.

At full production at Berwind, we expect to produce approximately 750,000 tons per year of high quality low-volatile coal with total cash costs per ton in the low- to mid-$70’s for company produced coal.

We expect to have initial production by late 2021, and to ramp up to full production levels by the second quarter of 2022.

The slope project allows us to transition our mining efforts at Berwind to the thicker Pocahontas No.

At full production at Berwind, we expect to produce approximately 750,000 tons per year of high quality low-volatile coal with total cash costs per ton in the low to mid-$70s for company produced coal, at midcycle pricing.

When including the recently acquired Amonate reserves at our Berwind Complex, we ultimately anticipate over 1.5 million tons of annual production at Berwind.

We estimate that the mine life for the Berwind Complex is almost 20 years.

We are currently mining a small amount of coal from the Triad mine at Berwind.

The mine is anticipated to produce less than 250,000 tons in 2021, and should function as a bridge until the main Berwind Pocahontas #4 reserve is fully activated.

We have the necessary permits for the Berwind mine for our current and budgeted operations.

A permit for our Squire Jim seam room-and-pillar underground mine was issued during 2020.

The mine began production in 2021 and will continue in 2022 until exhaustion.

It will function as a bridge until the main Berwind Pocahontas No.

4 reserve is fully activated.

We have the necessary permits for the Berwind Complex for our current and budgeted operations.

A permit for our Squire Jim seam room-and-pillar underground mine was issued during 2020 and contains a large area of Squire Jim seam coal deposits.

The Squire Jim seam of coal is the lowest known coal seam on the geologic column in this region, and due to depth of cover has never been significantly explored.

At this point, we do not anticipate activating this mining permit.

The Knox Creek property consists of approximately 62,100 acres of controlled mineral, a 650 tons per hour preparation plant and coal-loading facility along with a refuse impoundment.

In December 2021, we acquired the Amonate Assets from Coronado, pursuant to an asset purchase agreement.

The acquisition, for a total cash consideration of $30 million, included a mine complex located in McDowell County, West Virginia and Tazewell County, Virginia adjacent and contiguous to the Company’s existing Berwind Complex.

The acquisition primarily consists of high quality, low and mid-volatile metallurgical coal reserves and resources, much of which will be mined from the Company’s Berwind Complex.

Also purchased were several additional permitted mines and a currently idled 1.3-million ton per annum capacity coal preparation plant.

We began mine development on the Amonate Assets and refurbishment of the existing but idled preparation facilities immediately.

Initial production is expected by the second quarter of 2022, with total new incremental production for the entire year at approximately 200,000 tons.

Given the proximity of the facility to our existing Berwind Complex, the Company expects to meaningfully utilize the facility as soon as the refurbishing efforts allow.

We expect to incur approximately $10 million of capital expenditures in 2022 to bring the new plant at the Berwind Complex online.

Ultimately, the combined Berwind Complex and Amonate Assets can produce over 1.5 million tons per year of primarily low-vol saleable coal.

Once refurbished, the new Berwind preparation plant will be served by the Norfolk Southern railroad.

The Knox Creek property consists of approximately 62,100 acres of controlled mineral, a 650 tons per hour preparation plant and a coal-loading facility along with a refuse impoundment.

Rail service is provided by Norfolk Southern.

The Tiller Mine slope face-up and shafts were idled before our acquisition of the property.

We have spent limited amounts of capital to review the feasibility of a high volatile A metallurgical deep mine in the Jawbone seam of coal.

This seam is located slightly above the Tiller Seam and would be accessed via a short slope.

We have spent limited amounts of capital to review the feasibility of a high-vol A metallurgical deep mine in the Jawbone seam of coal.

This seam is located slightly above the Tiller Seam and would be accessed via a short slope from within the existing Tiller seam mine.

Jawbone coal could flow through the same portal and slope as the idle Tiller mine.

Production is expected to resume once market conditions warrant such.

From time to time, we process coal purchased from other independent producers at the Knox Creek preparation plant and load-out facilities.

We also process and load coal trucked from our Berwind mine at this facility.

We also process and load coal trucked from our Berwind Complex at this facility until the Amonate plant is brought online.

In the fourth quarter of 2019, we acquired multiple permits from various affiliates of Omega Highwall Mining, LLC.

Consideration for the transaction included assumption of approximately $0.6 million of ARO liability, curing minor lease defaults, and paying advance royalties under two assumed lease instruments.

Consideration for the transaction included the assumption of approximately $0.6 million of asset retirement obligations (“ARO”) liability, curing minor lease defaults, and paying advance royalties under two assumed lease instruments.

The total out-of-pocket consideration was less than $0.1 million, most of which is recoupable against future royalty payments.

These permits are in close proximity to our Knox Creek preparation plant and loadout infrastructure, and provide immediate access to two separate mining areas in Southwestern Virginia.

One is a deep mine permit in the Jawbone Seam, which contains approximately 2.65 million tons of geologically advantaged metallurgical coal.

The second is a metallurgical surface mine in the Tiller and Red Ash seams that is spade ready for production.

It contains approximately 800,000 tons of coal that can be mined via the surface and highwall mining methods.

The surface mining is expected to have very low mining ratios.

The combination of close proximity to Knox Creek and advantaged geology make these two mines likely to become active in the next few years.

The fully permitted surface mine is one of the areas, subject to market conditions, that could positively impact near-term production and profitability.

It is possible that the surface mine will be operated utilizing third party contractors we would manage.

In February 2021, a new mine development project known as the Big Creek mine and located near our Knox Creek preparation plant was approved by our Board of Directors.

We anticipate to begin production at the Big Creek mine within approximately four to six months of breaking ground.

We have obtained all required permits to begin development of the Big Creek mine.

We anticipate full production of around 150,000-200,000 tons a year of primarily high quality, mid-volatile coal by the fourth quarter of 2021, with cash costs per ton in the upper $50’s for company produced coal.

We expect growth capital spending in the development of the Big Creek mine to be roughly $5-7 million over the next two quarters.

We expect this mine to be able to produce at these levels for more than three years.

Our RAM Mine property is located in southwestern Pennsylvania, consists of approximately 1,570 acres of controlled mineral and is scheduled for initial production after a mining permit is issued.

Production of high volatile coal from the Pittsburgh seam is planned from a single continuous-miner room-and-pillar underground operation.

One is a deep mine permit in the Jawbone Seam, a geologically advantaged metallurgical coal reserve and resource.

The second is a metallurgical surface mine in the Tiller seam that was spade ready for production at the time of acquisition and is mined via surface and highwall mining methods.

In August 2021, we began production at this new surface mine known as the Big Creek mine.

We added a highwall miner in the fourth quarter of 2021.

We anticipate full production of at least 300 thousand tons of primarily

high quality, mid-vol coal in 2022.

We expect Big Creek to be able to produce at these levels for approximately three years.

Our RAM Mine property is located in southwestern Pennsylvania, consists of approximately 1,570 acres of controlled mineral.

Production of high-vol coal from the Pittsburgh seam is planned from a single continuous-miner room-and-pillar underground operation.

The Pittsburgh seam, in close proximity to Pittsburgh area coke plants, has historically been a key feedstock for these coke plants.

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In addition to close proximity to river barge facilities, our RAM Mine operations are also near Norfolk Southern rail access.

The RAM Mine coal reserve is not yet permitted, although we have applied for a permit and it is in the final phase of the permit application process.

We expect this permit to be issued in 2021.

Our RAM Mine property initial production is subject to a final mining permit being issued and market conditions warrant development.

Customers and Contracts

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During 2020, sales to three customers accounted for approximately 70% of total revenue.

The total balance due from these two customers at December 31, 2019 was approximately 58% of total accounts receivable.

The total balance due from these three customers at December 31, 2020 was approximately 46% of total accounts receivable.

No other customer accounted for more than 10% of our revenue during this period.

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The names of the seams in which we have coal reserves, and attributes thereof, are widely recognized in the metallurgical coal market.

Our principal domestic competitors include Blackhawk Mining, LLC, Coronado Global Resources, Inc., Corsa Coal Corp, Arch Resources, Inc., Alpha Metallurgical Resources, Inc., Energy, Inc.

and Warrior Met Coal, Inc.

We also compete in international markets directly with domestic companies and with companies that produce coal from one or more foreign countries, such as Australia, Canada, Colombia and South Africa.

Our principal domestic competitors include Alpha Metallurgical Resources, Inc., Blackhawk Mining, LLC, Coronado, Arch Resources, Inc., Peabody Energy Corporation and Warrior Met Coal, Inc.

We also compete in international markets directly with domestic companies and with companies that produce coal from one or more foreign countries, such as Australia, Canada, and Colombia.

Many of these coal producers are larger than we are and have greater financial resources and larger reserve bases than we do.

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Environmental, Health and Safety and Other Regulatory Matters

Our operations are subject to federal, state, and local laws and regulations, such as those relating to matters such as permitting and licensing, employee health and safety, reclamation and restoration of mining properties, water discharges, air emissions, plant and wildlife protection, the storage, treatment and disposal of wastes, remediation of contaminants, surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions.

Compliance with these laws and regulations may be costly and time-consuming and may delay commencement, continuation or expansion of exploration or production at our facilities.

They may also depress demand for our products by imposing more stringent requirements and limits on our customers’ operations.

Moreover, these laws are constantly evolving and are becoming increasingly complex and stringent over time.

These laws and regulations, particularly new legislative or administrative proposals, or judicial interpretations of existing laws and regulations related to the protection of the environment could result in substantially increased capital, operating and compliance costs.

Our operations are subject to numerous federal, state, and local environmental, health and safety laws and regulations, such as those relating to permitting and licensing matters, employee health and safety, reclamation and restoration of mining properties, water discharges, air emissions, plant and wildlife protection, the storage, treatment and disposal of certain materials (including solid and hazardous wastes), remediation of contaminants, surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions.

Compliance with these laws and regulations may be costly and time-consuming, delay commencement, continuation or expansion of exploration or production at our facilities, and depress demand for our products by imposing more stringent requirements and limits on our customers’ operations.

Moreover, these laws are constantly evolving and the trend has been for increasingly complex and stringent regulation over time.

New legislative or administrative proposals, or judicial interpretations of existing laws and regulations related to the protection of the environment could result in substantially increased capital, operating and compliance costs.

Due in part to these extensive and comprehensive regulatory requirements and ever-changing interpretations of these requirements, violations of these laws can occur from time to time in our industry and also in our operations.

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Surface Mining Control and Reclamation Act.

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) establishes operational, reclamation and closure standards for our mining operations and requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities.

SMCRA also stipulates compliance with many other major environmental statutes, including the CAA, the CWA, the ESA, RCRA and CERCLA.

Permits for all mining operations must be obtained from the United States Office of Surface Mining Reclamation and Enforcement (“OSMRE”) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority.

Our operations are located in states which have achieved primary jurisdiction for enforcement of SMCRA through approved state programs.

SMCRA imposes a complex set of requirements covering all facets of coal mining.

The Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”) establishes comprehensive operational, reclamation and closure standards for our mining operations and requires that such standards be met during the course of and following completion of mining activities.

The SMCRA also stipulates compliance with many other major environmental statutes, including the Clean Air Act (the “CAA”), the Clean Water Act (the “CWA”), the Endangered Species Act (the “ESA”), the Resource Conservation and Recovery Act (the “RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (the “CERCLA”).

Permits for all mining operations must be obtained from the United States Office of Surface Mining Reclamation and Enforcement (the “OSMRE”) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority.

Our operations are located in West Virginia, Virginia, and Pennsylvania, which have achieved primary jurisdiction for enforcement of SMCRA through approved state programs.

The SMCRA imposes a complex set of requirements covering all facets of coal mining.

SMCRA regulations govern, among other things, coal prospecting, mine plan development, topsoil or growth medium removal and replacement, disposal of excess spoil and coal refuse, protection of the hydrologic balance, and suitable post mining land uses.

From time to time, OSMRE will also update its mining regulations under SMCRA.

For example, OSMRE has previously sought to impose stricter stream protection requirements by requiring more extension pre-mining and baseline data for coal mining operations.

The rule was disapproved by Congress pursuant to the Congressional Review Act (“CRA”).

However, whether Congress will enact future legislation to require a new Stream Protection Rule remains uncertain.

From time to time, the OSMRE will also update its mining regulations under the SMCRA.

For example, the OSMRE has previously sought to impose stricter stream protection requirements by requiring more extension pre-mining and baseline data for coal mining operations.

The rule was disapproved by Congress pursuant to the Congressional Review Act.

However, whether Congress will enact future legislation to require a new stream protection

rule remains uncertain.

The existing rules, or other new SMCRA regulations, could result in additional material costs, obligations and restrictions upon our operations.

Abandoned Mine Lands Fund.

SMCRA also imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (“AML Fund”), which is used to restore unreclaimed and abandoned mine lands mined before 1977.

The current per ton fee is $0.28 per ton for surface-mined coal and $0.12 per ton for underground-mined coal.

These fees are currently scheduled to be in effect until September 30, 2021.

The SMCRA also imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (the “AML Fund”), which is used to restore unreclaimed and abandoned mine lands mined before 1977.

The adjusted fees proposed in the pending Interim Final Rule per ton for October 1, 2021 through September 30, 2034 are (i) 22.4 cents per ton for surface-mined anthracite, bituminous, and subbituminous coal if the value per ton is $2.24 per ton or more, (ii) 9.6 cents per ton for underground-mined anthracite, bituminous, and subbituminous coal if the value per ton is $0.96 per ton, and (iii) 6.4 cents per ton for surface- and underground-mined lignite coal if the value per ton is $3.20 per ton or more.

The Interim Final Rule took effect on January 14, 2022, but the OSMRE is accepting comments until February 14, 2022.

Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience related to similar activities.

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We are required to prepare and present to federal, state, and local authorities data detailing the effect or impact that any proposed exploration project for production of coal may have upon the environment, the public and our employees.

The permitting rules, and the interpretations of these rules, are complex, change frequently, and may be subject to discretionary interpretations by regulators.

The requirements imposed by these permits and associated regulations can be costly and time-consuming and may delay commencement or continuation of exploration, production or expansion at our operations.

The governing laws, rules, and regulations authorize substantial fines and penalties, including revocation or suspension of mining permits under some circumstances.

The permitting rules are complex and continuously updated, and may be subject to discretionary interpretations by regulators.

Further, the laws, rules, and regulations that govern our mining operations authorize substantial fines and penalties, including revocation or suspension of mining permits under some circumstances.

Monetary sanctions and, in certain circumstances, even criminal sanctions may be imposed for failure to comply with these laws.

Applications for permits and permit renewals at our mining operations are also subject to public comment and potential legal challenges from third parties seeking to prevent a permit from being issued, or to overturn the applicable agency’s grant of the permit.

Should our permitting efforts become subject to such challenges, the permits may not be issued in a timely fashion, may involve requirements which restrict our ability to conduct our mining operations or to do so profitably, or may not be issued at all.

Compliance with required permits and associated regulations may have a material adverse impact on our operations, earnings, or financial condition.

Applications for permits and permit renewals associated with our mining operations are also subject to public comment and potential legal challenges from third parties seeking to prevent a permit from being issued, or to overturn the applicable agency’s grant of the permit.

Should our permitting efforts become subject to such challenges, the permits may not be issued in a timely fashion, may impose requirements which restrict our ability to conduct our mining operations or to do so profitably, or may not be issued at all.

Any delays, denials, or revocation of these or other similar permits we need to operate could reduce our production and materially adversely impact our cash flow and results of our operations.

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For example, the process of obtaining CWA permits can be particularly time-consuming and subject to delays and denials.

The EPA also has the authority to veto permits issued by the Corps under the CWA’s Section 404 program that prohibits the discharge of dredged or fill material into regulated waters without a permit.

The Environmental Protection Agency (the “EPA”) also has the authority to veto permits issued by the U.S.

of Engineers (the “Corps”) under the CWA’s Section 404 program that prohibits the discharge of dredged or fill material into regulated waters without a permit.

Even after we obtain the permits that we need to operate, many of the permits must be periodically renewed, or may require modification.

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Financial Assurance.

Federal and state laws require a mine operator to secure the performance of its reclamation and lease obligations under SMCRA through the use of surety bonds or other approved forms of financial security for payment of certain long-term obligations, including mine closure or reclamation costs.

The changes in the market for coal used to generate electricity in recent years have led to bankruptcies involving prominent coal producers.

Federal and state laws require a mine operator to secure the performance of its reclamation and lease obligations under the SMCRA through the use of surety bonds or other approved forms of financial security for payment of certain long-term obligations, including mine closure or reclamation costs.

in the market for coal used to generate electricity in recent years have led to bankruptcies involving prominent coal producers.

Several of these companies relied on self-bonding to guarantee their responsibilities under the SMCRA permits including for reclamation.

In response to these bankruptcies, OSMRE issued a Policy Advisory in August 2016 to state agencies that was intended to discourage authorized states from approving self-bonding arrangements.

In response to these bankruptcies, the OSMRE issued a policy advisory in August 2016 to state agencies that was intended to discourage authorized states from approving self-bonding arrangements (the “Policy Advisory”).

Although the Policy Advisory was rescinded in October 2017, certain states, including Virginia, had previously announced that they would no longer accept self-bonding to secure reclamation obligations under the state mining laws.

Additionally, in March 2018, the Government Accounting Office recommended that Congress consider amending SMCRA to eliminate the availability of self-bonding to guarantee responsibilities under SMCRA permits.

Individually and collectively, these and future revised various financial assurance requirements may increase the amount of financial assurance needed and

limit the types of acceptable instruments, straining the capacity of the surety markets to meet demand.

Additionally, in March 2018, the Government Accounting Office recommended that Congress consider amending the SMCRA to eliminate the availability of self-bonding to guarantee responsibilities under SMCRA permits.

Individually and collectively, these and future revised various financial assurance requirements may increase the amount of financial assurance needed and limit the types of acceptable instruments, straining the capacity of the surety markets to meet demand.

This may delay the timing for and increase the costs of obtaining the required financial assurance.

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Mine Safety and Health.

The Mine Act and the MINER Act, and regulations issued under these federal statutes, impose stringent health and safety standards on mining operations.

The Federal Mine Safety and Health Act of 1977, as amended (the “MINE Act”) and the Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), and regulations issued under these federal statutes, impose stringent health and safety standards on mining operations.

The regulations that have been adopted under the Mine Act and the MINER Act are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, roof control, ventilation, blasting, use and maintenance of mining equipment, dust and noise control, communications, emergency response procedures, and other matters.

MSHA regularly inspects mines to ensure compliance with regulations promulgated under the Mine Act and MINER Act.

The Mine Safety and Health Administration (the “MSHA”) regularly inspects mines to ensure compliance with regulations promulgated under the Mine Act and MINER Act.

Pennsylvania, West Virginia, and Virginia all have similar programs for mine safety and health regulation and enforcement.

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Our compliance with current or future mine health and safety regulations could increase our mining costs.

At this time, it is not possible to predict the full effect that new or proposed statutes, regulations and policies will have on our operating costs, but any expansion of existing regulations, or making such regulations more stringent may have a negative impact on the profitability of our operations.

have a negative impact on the profitability of our operations.

If we were to be found in violation of mine safety and health regulations, we could face penalties or restrictions that may materially and adversely impact our operations, financial results and liquidity.

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Moreover, if one of our operations is issued a notice of pattern of violations, then MSHA can issue an order withdrawing the miners from the area affected by any enforcement action during each subsequent significant and substantial (“S&S”) citation until the S&S citation or order is abated.

Workers’ Compensation and Black Lung.

Workers’ Compensation and Occupational Disease.

We are insured for workers’ compensation benefits for work related injuries that occur within our United States operations.

We retain first-dollar coverage for all of our subsidiaries and are insured for the statutory limits.

We retain insurance coverage for all of our subsidiaries and are insured for the statutory limits.

Workers’ compensation liabilities, including those related to claims incurred but not reported, are recorded principally using annual valuations based on discounted future expected payments using historical data of the operating subsidiary or combined insurance industry data when historical data is limited.

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These types of lawsuits are not uncommon and could have a significant impact on our operating costs.

In addition, we obtained from a third-party insurer a workers’ compensation insurance policy, which includes coverage for medical and disability benefits for black lung disease under the Federal Coal Mine Health and Safety Act of 1969 and the Mine Act, as amended.

In addition, we obtained from a third-party insurer a workers’ compensation insurance policy, which includes coverage for medical and disability benefits for occupational disease under the Federal Coal Mine Health and Safety Act of 1969 and the Mine Act.

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 pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970.

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Direct impacts on coal mining and processing operations include CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter such as fugitive dust.

The CAA indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants.

The CAA indirectly impacts coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants.

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 our coal, directly or indirectly, include, but are not limited to, the following:

● Cross-State Air Pollution Rule.

In June 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”), a cap-and-trade program that requires 28 states in the Midwest and eastern seaboard of the U.S.

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (the “CSAPR”), a cap-and-trade program that requires 28 states in the Midwest and eastern seaboard of the U.S.

to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states.

In May 2017, EPA further limited summertime (May-September) nitrogen oxide emissions from power plants in 22 states in the eastern United States in the CSAPR Update Rule.

In May 2017, the EPA further limited summertime (May-September) nitrogen oxide emissions from power plants in 22 states in the eastern United States in the CSAPR Update Rule.

For states to meet these requirements, a number of coal-fired electric generating units will likely need to be retired, rather than retrofitted with the necessary emission control technologies, reducing demand for thermal coal.

Moreover, in September 2019, the United States Court of Appeals for the District of Columbia Circuit (“D.C.

Circuit”) remanded the CSAPR Update Rule to EPA on the grounds that it failed to timely require upwind states to control or eliminate their contribution to ozone and/or fine particulate matter in downwind states, as required under the federal Clean Air Act.

In October 2020, EPA proposed a Revised CSAPR Update Rule in response to the D.C.

Circuit’s ruling.

The proposed rule addresses 21 states’ outstanding interstate pollution transport obligations and would require additional emissions reductions of nitrogen oxides from power plants in 12 states.

Circuit”) remanded the CSAPR Update Rule to the EPA on the grounds that it failed to timely require upwind states to control or eliminate their contribution to ozone and/or fine particulate matter in downwind states, as required under the CAA.

In October 2020, the EPA proposed a Revised CSAPR Update Rule in response to the D.C.

Circuit’s ruling, which was finalized in April 2021.

The final rule resolves 21 states’ outstanding interstate pollution transport obligations and would require additional emissions reductions of nitrogen oxides from power plants in 12 states.

Imposition of stricter deadlines for controlling downwind contribution could accelerate unit retirements or the need to implement emission control strategies.

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However, the practical impact of CSAPR may be limited because utilities in the U.S.

have continued to take steps to comply with CAIR, which requires similar power plant

emissions reductions, and because utilities are preparing to comply with the Mercury and Air Toxics Standards (“MATS”) regulations, which require overlapping power plant emissions reductions.

have continued to take steps to comply with the Clean Air Interstate Rule, which requires similar power plant emissions reductions, and because utilities are also required to comply with the Mercury and Air Toxics Standards (the “MATS”) regulations, finalized in 2020, which require overlapping power plant emissions reductions.

● Acid Rain .

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● NAAQS for Criterion Pollutants.

The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants:

The CAA requires the EPA to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for six common air pollutants:

carbon monoxide, nitrogen dioxide, lead, ozone, particulate matter and sulfur dioxide.

Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels.

The EPA has adopted NAAQS for nitrogen oxide, sulfur dioxide, particulate matter and ozone.

The CAA further requires EPA to periodically review and revise the NAAQS, resulting in the adoption of increasingly more stringent standards over time.

States with areas non-attainment areas must adopt a state implementation plan (“SIP”) that demonstrates compliance with the existing or new air quality standards.

The EPA has adopted NAAQS for carbon monoxide, nitrogen dioxide, sulfur dioxide, particulate matter and ground-level ozone.

The CAA further requires the EPA to periodically review and revise the NAAQS, resulting in the adoption of increasingly more stringent standards over time.

States with non-attainment areas must adopt a state implementation plan that demonstrates compliance with the existing or new air quality standards.

These plans could require significant additional emissions control expenditures at coal-fired power plants.

The final rules and new standards may also impose additional emissions control requirements on our customers in the electric generation, steelmaking, and coke industries.

New rules and standards may also impose additional emissions control requirements on our customers in the electric generation, steelmaking, and coke industries.

Because coal mining operations emit particulate matter and sulfur dioxide, our mining operations could be affected when the new standards are implemented by the states.

● Mercury and Hazardous Air Pollutants .

The EPA has established emission standards for mercury and other metal, fine particulates, and acid gases from coal- and oil-fired power plants through the Mercury and Air Toxics Standards (“MATS”) rule.

The EPA has established emission standards for mercury and other metal, fine particulates, and acid gases from coal- and oil-fired power plants through the MATS rule.

In May 2020, the EPA published a final rule reversing its prior determination that it is appropriate and necessary to regulate these pollutants.

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There is widespread concern about the contributions of human activity to such changes, especially through the emission of GHGs.

Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate.

There are three primary sources of GHGs associated with the coal industry.

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Second, combustion of fuel by equipment used in coal production and to transport our coal to our customers is a source of GHGs.

Third, coal mining itself can release methane, which is considered to be a more potent GHG than CO2, directly into the atmosphere.

Third, coal mining itself can release methane, which is considered to be a more potent GHG than carbon dioxide, directly into the atmosphere.

These emissions from coal consumption, transportation and production are subject to pending and proposed regulation as part of initiatives to address global climate change.

As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.

As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, state and local levels of government to monitor and limit emissions of GHGs.

Collectively, these initiatives could result in higher electric costs to our customers or lower the demand for coal used in electric generation, which could in turn adversely impact our business.

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The market for our coal may be adversely impacted if comprehensive legislation or regulations focusing on GHG emission reductions are adopted, or if our customers are unable to obtain financing for their operations.

At the international level, President Obama announced in November 2014 that the United States would seek to cut net GHG emissions 26-28 percent below 2005 levels by 2025 in return for China’s commitment to seek to peak emissions around 2030, with concurrent increases in renewable energy.

In April 2016, the United States further agreed to

voluntarily limit or reduce future emissions as part of the Paris Agreement reached at the United Nations Conference on Climate Change.

At the international level, in April 2016, the United States agreed to voluntarily limit or reduce future emissions as part of the Paris Agreement reached at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change.

In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement and withdrew from the agreement in November 2020.

However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that will allow the United States to rejoin the Paris Agreement.

The newly signed acceptance, deposited with the United Nations on January 20, 2021, reverses the prior withdrawal.

The United States will officially rejoin the Paris Agreement on February 19, 2021.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021.

In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change.

Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations.

In November 2021, the 26th Conference of the Parties to the United Nations Framework on Climate Change concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions.

46 countries signed onto a Global Coal to Clean Energy Transition Statement, committing to transition away from unabated coal power generation by about 2030 for “major economies” and a global transition by roughly 2040.

International commitments, reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations.

At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S.

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Furthermore, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment, because emissions of GHGs are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.

Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA.

For example, in August 2015, EPA finalized the CPP to cut carbon emissions from existing power plants.

The CPP creates individualized emission guidelines for states to follow, and requires each state to develop an implementation plan to meet the individual state’s specific targets for reducing GHG emissions.

In July 2019, the EPA adopted a rule that replaced the CPP with a new rule titled the Affordable Clean Energy (“ACE”) Rule.

Although the ACE rule moves away from the individualized emission guidelines of the CPP, it still requires states to set appropriate GHG emission standards for power plants within their jurisdiction based upon the application of “candidate” heat rate improvement measures.

The implementation of the ACE rule is currently being challenged in the D.C.

These and future GHG emission standards may encourage a shift away from coal-fired power generation, adversely impacting the market for our product.

Based on these findings, the EPA, over time, has attempted to restrict emissions of GHGs under existing provisions of the CAA.

For example, in August 2015, the EPA finalized the Clean Power Plan (the “CPP”) to cut carbon emissions from existing power plants.

The CPP did not formally go into effect because the Supreme Court stayed its implementation in February 2016 and in July 2019, the EPA adopted a rule that repealed and replaced the CPP.

The new rule, titled the Affordable Clean Energy Rule (the “ACE Rule”), required states to set appropriate GHG emission standards for power plants within their jurisdiction based upon the application of “candidate” heat rate improvement measures.

Circuit repealed the ACE Rule in 2021, and there is ongoing litigation challenging the repeal of both the CPP and the ACE Rule.

The EPA’s authority to regulate GHG emissions from existing power plants under the CAA and the reversal of the ACE Rule are currently being challenged at the Supreme Court.

The outcome of this litigation, any future rules or future GHG emission standards may encourage a shift away from coal-fired power generation, adversely impacting the market for our product.

At the state level, several states, including Pennsylvania and Virginia, have already adopted measures requiring GHG emissions to be reduced within state boundaries, including cap-and-trade programs and the imposition of renewable energy portfolio standards.

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

The uncertainty over the outcome of litigation challenging the ACE rule and the extent of future regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants.

Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of GHG emissions could decrease demand for thermal coal, thereby reducing our revenue and adversely affecting our business and results of operations.

We or prospective customers may also have to invest in CO2 capture and storage technologies in order to burn coal and comply with future GHG emission standards.

Finally, there have been attempts to encourage the reduction of coalbed methane emissions because methane has a greater GHG effect than CO2 and can give rise to safety concerns.

For example, EPA has established the Coalbed Methane Outreach Program (“CMOP”) in an effort to mitigate methane emissions from underground coal mines through voluntary initiatives and outreach.

The uncertainty over the outcome of litigation challenging the repeal of both the ACE Rule and the CPP and the extent of future regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants.

Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of GHG emissions could decrease

demand for thermal coal, thereby reducing our revenue and adversely affecting our business and results of operations.

We or prospective customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal and comply with future GHG emission standards.

Finally, there have been attempts to encourage the reduction of coalbed methane emissions because methane has a greater GHG effect than carbon dioxide and can give rise to safety concerns.

For example, the EPA has established the Coalbed Methane Outreach Program in an effort to mitigate methane emissions from underground coal mines through voluntary initiatives and outreach in partnership with the coal industry.

If new laws or regulations were introduced to reduce coalbed methane emissions, those rules could adversely affect our costs of operations by requiring installation of air pollution controls, higher taxes, or costs incurred to purchase credits that permit us to continue operations.

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Likewise, permits are required under the CWA to construct impoundments, fills or other structure in areas that are designated as 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.

For example, prior to placing fill material in waters of the United States, such as with the construction of a valley fill, coal mining companies are required to obtain a permit from

the Corps under Section 404 of the CWA.

For example, prior to placing fill material in waters of the United States, such as with the construction of a valley fill, coal mining companies are required to obtain a permit from the Corps under Section 404 of the CWA.

The permit can be either a Nationwide Permit (“NWP”), normally NWP 21, 49 or 50 for coal mining activities, or a more complicated individual permit.

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The EPA has the authority to veto permits issued by the Corps under the CWA’s Section 404 program that prohibits the discharge of dredged or fill material into regulated waters without a permit.

Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements.

Additionally, recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements, such as an April 2020 decision further defining the scope of the CWA, wherein the U.S.

Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

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.

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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.

Changes and proposed changes in state and federally recommended water quality standards may result in the issuance or modification of permits with new or more stringent effluent limits or terms and conditions.

Potential changes in state and federally recommended water quality standards may result in the issuance or modification of permits with new or more stringent effluent limits or terms and conditions.

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 (“TMDL”) regulations, which may lead to the adoption of more stringent discharge standards for our coal mines and could require more costly treatment.

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Finally, in June 2015, the EPA and the Corps published a new definition of “waters of the United States” (“WOTUS”) that would have expanded areas requiring NPDES or Corps Section 404 permits.

In October 2019, EPA and the Army Corps of Engineers issued a final rule that repealed the 2015 WOTUS definition and reinstated the agencies’ narrower pre-2015 scope of federal CWA jurisdiction.

In April 2020, EPA and the Army Corps of Engineers issued the final Navigable Waters Protection Rule amending the definition of “water of the United States” and replacing EPA’s October 2019 final rule.

Judicial challenges to EPA’s October 2019 and April 2020 final rules are currently before multiple federal district courts.

If the October 2019 final rules are vacated and the expanded scope of jurisdiction in the 2015 rule is ultimately implemented, the CWA permits we need may not be issued, may not be issued in a timely fashion, or may be issued with new requirements which restrict our ability to conduct mining operations or to do so profitably.

This definition never took effect as it was replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019.

A coalition of states and cities, environmental groups and agricultural groups challenged the NWPR, which was vacated by the U.S.

District Court for the District of Arizona in August 2021.

The EPA is undergoing a rulemaking process to redefine the definition of WOTUS;

in the interim, the EPA is utilizing the pre-2015 WOTUS definition until further notice.

To the extent a new rule or further litigation expands the scope of the CWA’s jurisdiction, the CWA permits we need may not be issued, may not be issued in a timely fashion, or may be issued with new requirements which restrict our ability to conduct mining operations or to do so profitably.

Resource Conservation and Recovery Act.

RCRA and corresponding state laws establish standards for the management of solid and hazardous wastes generated at our various facilities.

Besides affecting current waste disposal practices, RCRA also addresses the environmental effects of certain past hazardous waste treatment, storage and disposal practices.

In addition, RCRA requires certain of our facilities to evaluate and respond to any past release, or threatened release, of a hazardous substance that may pose a risk to human health or the environment.

RCRA may affect coal mining operations by establishing requirements for the proper management, handling, transportation and disposal of solid and hazardous wastes.

For example, EPA regulates coal ash as a solid waste under Subtitle D of RCRA through its coal combustion residuals (“CCR”) rule.

The RCRA and corresponding state laws establish standards for the management of solid and hazardous wastes generated at our various facilities.

Besides affecting current waste disposal practices, the RCRA also addresses the environmental effects of certain past hazardous waste treatment, storage and disposal practices.

In addition, the RCRA requires certain of our facilities to evaluate and respond to any past release, or threatened release, of a hazardous substance that may pose a risk to human health or the environment.

The RCRA may affect coal mining operations by establishing requirements for the proper management, handling, transportation and disposal of solid and hazardous wastes.

For example, the EPA regulates coal ash as a solid waste under Subtitle D of the RCRA through its coal combustion residuals (“CCR”) rule.

This rule establishes limits for the location of new sites and requires closure of sites that fail to meet prescribed engineering standards, regular inspections of impoundments, and immediate remediation and closure of unlined ponds that are polluting ground water.

As initially promulgated, the rule exempted closed coal ash impoundments located at inactive facilities and allowed for the continued operation of unlined or clay-lined ponds that were not polluting groundwater.

However, in August 2020, EPA finalized amendments to its CCR rule that would require closure to be initiated at all unlined and clay-lined surface

impoundments by April 11, 2021.

Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule.

However, in August 2020, the EPA finalized amendments to its CCR rule that required closure to be initiated at all unlined and clay-lined surface impoundments by April 11, 2021.

Then, on January 11, 2022, the EPA announced several actions with respect to the CCR rule, including reiterating that surface impoundments cannot be closed with coal ash in contact with groundwater (in connection with proposed determinations to deny closure deadline extensions) and establishing a federal permitting scheme for the disposal of coal ash and establishing regulations for legacy coal ash surface impoundments.

Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate the EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule.

These requirements, as well as any future changes in the management of coal combustion residuals, 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 coal combustion residuals, including coal ash, could lead to material liability for our customers under RCRA or other federal or state laws and potentially further reduce the demand for coal.

Currently, certain coal mine wastes, such as earth and rock covering a mineral deposit (commonly referred to as overburden) and coal cleaning wastes, are exempted from hazardous waste management under RCRA.

In addition, contamination caused by the past disposal of coal combustion residuals, including coal ash, could lead to material liability for our customers under the RCRA or other federal or state laws and potentially further reduce the demand for coal.

Any change or reclassification of this exemption could significantly increase our coal mining costs.

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Compliance with the requirements of the ESA and the Bald and Golden Eagle Protection Act could have the effect of prohibiting or delaying us from obtaining mining permits.

These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats.

requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats.

Use of Explosives.

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National Environmental Policy Act.

NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment, such as issuing a permit or other approval.

The National Environmental Policy Act (the “NEPA”) requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment, such as issuing a permit or other approval.

In the course of such evaluations, an agency will typically prepare an environmental assessment to determine the potential direct, indirect and cumulative impacts of a proposed project.

Where the activities in question have significant impacts to the environment, the agency must prepare an environmental impact statement.

Compliance with NEPA can be time-consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands, and may require public comment.

Furthermore, whether agencies have complied with NEPA is subject to protest, appeal or litigation, which can delay or halt projects.

NEPA review process, including potential disputes regarding the level of evaluation required for climate change impacts, may extend the time and/or increase the costs and difficulty of obtaining necessary governmental approvals, and may lead to litigation regarding the adequacy of the NEPA analysis, which could delay or potentially preclude the issuance of approvals or grant of leases.

In the past, the Council on Environmental Quality (“CEQ”) has issued guidance encouraging agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable GHG emissions and effects.

Although this guidance has since been withdrawn, the adoption of a similar guidance in the future could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our operations due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.

Compliance with the NEPA can be time-consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands, and may require public comment.

Furthermore, whether agencies have complied with the NEPA is subject to protest, appeal or litigation, which can delay or halt projects.

The NEPA review process, including potential disputes regarding the level of evaluation required for climate change impacts, may extend the time and/or increase the costs and difficulty of obtaining necessary governmental approvals, and may lead to litigation regarding the adequacy of the NEPA analysis, which could delay or potentially preclude the issuance of approvals or grant of leases.

In the past, the Council on Environmental Quality (the “CEQ”) has issued guidance encouraging agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable GHG emissions and effects.

Furthermore, the CEQ is currently reviewing proposed revisions to the NEPA regulations that would revise the definition of “effects” to expressly include direct, indirect, and cumulative effects, reduce the emphasis on the applicant’s purpose and need, and allow agencies to adopt NEPA regulations that are more rigorous than the CEQ regulations.

Although this proposed rule has yet to take effect, the adoption of a similar guidance in the future could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our operations due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.

Other Environmental Laws.

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We believe our employees are a competitive advantage.

We seek to foster a culture that supports diversity and inclusion, and strive to provide a safe, healthy and rewarding work environment with opportunities for growth.

We seek to foster a culture that supports diversity, equity and inclusion, and strive to provide a safe, healthy and rewarding work environment with opportunities for growth.

We had 454 employees as of December 31, 2021, including our named executive officers.

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We believe we have good relations with our employees.

Our human capital resources objectives include, as applicable, identifying, recruiting, training, retaining, incentivizing and integrating our existing and additional employees.

Our human capital resources objectives include, as applicable, identifying, recruiting, training, retaining, incentivizing and integrating our existing

and additional employees.

We also depend on experienced contractors and third-party consultants to conduct some of our day-to-day activities.

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As a result, we look for opportunities to celebrate accomplishments and to build pride in our operational safety and performance.

Jumpstart Our Business Startups Act (“JOBS Act”)

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”).

Jumpstart Our Business Startups Act ( the “JOBS Act”)

We are an “emerging growth company” as defined in the JOBS Act.

For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:

● provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

● comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

● provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on the executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”);

● obtain stockholder approval of any golden parachute payments not previously approved.

We will cease to be an emerging growth company upon the earliest of:

● the last day of the fiscal year in which we have $1.07 billion or more in annual revenues;

● the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of our most recently completed second fiscal quarter);

● the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period;

● the last day of the fiscal year following the fifth anniversary of our initial public offering, which will be December 31, 2022.

We will cease to be an emerging growth company the last day of the fiscal year following the fifth anniversary of our initial public offering, which is December 31, 2022.

Available Information

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Item 1. Business