What changed in this filing

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Item 1. Business

2023-03-14 compared with 2022-04-01 · 158 added, 124 removed, 399 unchanged (41% of the section changed)

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Our principal corporate offices are located in Lexington, Kentucky.

As used herein, “Ramaco Resources,” “we,” “our,” and similar terms include Ramaco Resources, Inc.

As used herein, “Ramaco Resources,” “the Company,” “we,” “our,” and similar terms include Ramaco Resources, Inc.

and its subsidiaries, unless the context indicates otherwise.

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 39 million reserve tons and 769 million resource tons of high-quality metallurgical coal.

We are a pure play metallurgical coal company with 62 million reserve tons and 1,156 million measured and indicated 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:

Our development portfolio primarily includes the following properties:

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.

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 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”).

In addition, the Company completed acquisitions of Ramaco Coal and Maben Coal in the second and third quarter of 2022, respectively.

With the Ramaco Coal acquisition, we control mineral deposits near Sheridan, Wyoming along with facilities that house research and development activities.

With the Maben Coal acquisition, we have obtained control of additional coal deposits in Wyoming County and Raleigh County, West Virginia.

Our operations include six active mines 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 20,200 acres of controlled mineral rights and contains approximately 16 seams that we have targeted for production.

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.

The Company commenced expansion of the Elk Creek preparation plant during 2022 to increase production in future periods.

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

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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.

The Berwind property consists of approximately 62,500 acres of controlled mineral rights, including the December 2021 acquisition of “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.

The Berwind Complex experienced an ignition event during 2022 that resulted in idling mining operations for one of the active mines.

Production restarted for the idle mine in the first quarter of 2023.

Our Knox Creek facility includes a preparation plant and 74,400 acres of controlled mineral rights that we expect to develop in the future.

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.

The Knox Creek preparation plant processes coal from our Berwind Complex (until the newly acquired plant at the Berwind Complex is fully up and running) as well as coal mined from the rights acquired in the Maben Coal transaction, discussed below, and coal purchased 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.

The Ramaco Coal acquisition in 2022 provides the Company with 16,000 acres of controlled mineral rights that we expect to develop in the future, including possible rare earth elements, as well as a research and pilot facility related to the production of advanced carbon products and materials from coal.

The Maben Coal acquisition in 2022 provides the Company with 28,000 leased acres of controlled mineral rights, which includes coal deposits that may be mined currently by surface and high wall mining methods as well as developed in the future through deep mining.

As of December 31, 2022, our estimated aggregate annual production capacity is approximately 2.7 million clean tons of coal.

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 plan to complete development of our existing properties and increase annual production over the next few years to approximately 6.5 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.

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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.

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

and Canadian metallurgical coal producers.

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Developing and Operating Our Metallurgical Coal Properties.

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.

We have 62 million and 1,156 million measured and indicated 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 plan to complete development of our existing properties and increase annual production over the next few years to approximately 6.5 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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We believe that business excellence is achieved through the pursuit of safer and more productive work practices.

Our properties are primarily located in southern West Virginia, southwestern Virginia, and southwestern Pennsylvania.

The following map shows the location of our mining complexes and projects:

Advancing our Initiatives in Rare Earth Elements and Advanced Carbon Products .

We are also focused on critical mineral rare earth development as well as the potential commercialization of coal-to-carbon-based products and materials.

These initiatives provide additional growth opportunities and upside potential in future periods.

Our properties are primarily located in southern West Virginia, southwestern Virginia, southwestern Pennsylvania, and northeastern Wyoming.

The following map shows the location of our mining complexes and projects, excluding our property located in Wyoming:

Elk Creek Mining Complex

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Additionally, almost all of this coal is high-fluidity, which is an important factor for high-volatile metallurgical coal.

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 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 estimate that the Elk Creek Complex contains reserves capable of yielding approximately 30 million tons of clean saleable metallurgical coal as well as measured and indicated metallurgical coal resource tons of 215 million.

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

We estimate that the mine life for the Elk Creek Complex is over 20 years.

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

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

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

The combined refuse capacity at the active disposal areas is expected to provide approximately 11 years of disposal life for our operations with additional refuse areas being permitted.

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.

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

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

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

We are actively pursuing multiple new permits.

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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.

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

We expect this upgrade will raise the nameplate processing capacity to 1,150 raw tons per hour and our annual processing capacity from this complex to approximately three million tons per year.

We expect that this upgrade will be completed in the second quarter of 2023.

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

These mines began production during the second quarter of 2022 and are expected to reach full levels of productivity during 2023.

Berwind Mining Complex

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.

The Berwind property consists of approximately 62,500 acres of controlled mineral rights, including the Amonate acquisition.

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

We view Berwind as the second flagship complex for Ramaco.

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.

3 seam and has since sloped up to current mining in the thicker Pocahontas No.

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 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 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.

In early 2021, as pricing and demand improved, Berwind development resumed, and we successfully reached the Pocahontas No.

4 seam in late 2021.

The Berwind Complex experienced an ignition event during the third quarter of 2022 that resulted in idling mining operations for one of the active mines.

Production restarted for the idle mine in the first quarter of 2023.

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

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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.

The acquisition 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 assets primarily consist 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 an idled 1.3 million ton per annum capacity coal preparation plant with a rail loading facility.

We began mine development on the Amonate Assets shortly after the acquisition.

Production began in the first quarter of 2022.

The preparation plant and rail loading facility were refurbished during 2022 and began operation in the fourth quarter of 2022.

Rail service is provided by Norfolk Southern.

Knox Creek Mining Complex

The Knox Creek Complex consists of approximately 74,400 acres of controlled mineral, a 750 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.

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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.

Production is expected to resume once warranted by market conditions.

We estimate that the mine life for the Knox Creek Complex is approximately 15 years.

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 Complex at this facility until the Amonate plant is brought online.

We may also process and load coal from our Berwind Complex at this facility until such time that the Berwind plant is fully up and running.

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

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, 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.

The second is a metallurgical surface mine in the Tiller seam that 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 1,567 acres of controlled mineral.

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

The Maben property is located in southern West Virginia and consists of approximately 28,000 acres of controlled mineral rights acquired from the purchase of Maben Coal in the third quarter of 2022.

As part of the transaction, we assumed existing mining permits issued by the West Virginia Department of Environmental Protection, which authorize mining by both surface and highwall mining methods as well as by underground methods.

The property also has issued permits covering an existing haul road as well as an active refuse disposal area together with a preparation plant and unit train loadout, neither of which had been constructed as of the closing date.

The Maben property contains various areas of high-quality low-vol metallurgical coal in the Sewell, Pocahontas 3, Pocahontas 4, and Pocahontas 6 seams of coal.

The Company expects that coal contained in the Sewell seam will be mined by surface and high-wall mining methods.

Initial production is expected to begin in the second quarter of 2023, reaching an annualized production rate of approximately 250,000 tons of low-volatile coal.

The Company will consider deep mine development of coal contained in Pocahontas 3 and 4 seams at a future point.

While the Company intends to utilize the Knox Creek preparation plant in the near term, such development would likely require construction of a new preparation plant and loadout as mentioned above.

The property is located in northeastern Wyoming, near Sheridan, and consists of approximately 16,000 acres of controlled mineral rights and a research and development facility that were acquired as part of the purchase of Ramaco Coal in the second quarter of 2022.

The property includes a thermal coal deposit and permit as well as occurrences of rare earth elements.

The mine is currently undergoing mineral analysis and core drilling assessment to assess the potential concentrations of rare earth elements.

This property is being used to support the Company’s possible expansion into the manufacture and commercialization of advanced carbon products and materials from coal.

The Company refers to this potentially new business line as “CORE” (Carbon Ore-Rare Earth), signifying its focus on carbon ore and rare earth elements.

Customers and Contracts

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The major factors influencing our business are the global economy and demand for steel.

We market the bulk of our production to North American integrated steel mills and coke plants, in addition to international customers primarily in Europe, South America, Asia and Africa.

We market the bulk of our production to North American integrated steel mills and coke plants, as well as international customers primarily in Europe, South America, Asia and Africa.

Additionally, we market limited amounts of our production to various premium-priced specialty markets, such as foundry cokemakers, manufacturers of activated carbon products, and specialty metals producers.

Coal quality and volumes are stipulated in coal sales agreements and, in many cases, the annual pricing and volumes are fixed.

Our contracts with customers typically require us to deliver coal with minimum specifications or qualities.

Variances from these specifications or qualities are settled by means of price adjustments.

Generally, the Company’s domestic sales contracts have terms of about one year and the pricing is typically fixed.

Export sales have spot or term contracts, and pricing can be either fixed or derived against index-based pricing mechanisms.

We sold 2.5 million tons of coal during 2022.

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Principally, our export market sales were made to Europe.

During 2021, sales to three customers accounted for approximately 58% of total revenue.

The total balance due from these three customers at December 31, 2021 was approximately 58% of total accounts receivable.

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

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.

During 2022, sales to two customers accounted for approximately 38% of total revenue.

No other customer accounted for 10% or more of our total revenue during 2022.

If a major customer decided to stop purchasing coal or significantly reduced its purchases from us, revenue could decline and our operating results and financial condition could be adversely affected.

Trade Names, Trademarks and Patents

We do not have any registered trademarks or trade names for our products, services or subsidiaries, and we do not believe that any trademark or trade name is material to our business.

We do not have any registered trademarks or trade names for our traditional products and services or subsidiaries, and we do not believe that any trademark or trade name is material to our traditional business.

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 Alpha Metallurgical Resources, Inc., Blackhawk Mining, LLC, Coronado, Arch Resources, Inc., Peabody Energy Corporation and Warrior Met Coal, Inc.

Trademarks related to CORE, the Company’s potentially new business line, could become material depending on future developments.

In connection with CORE, the Company holds 53 intellectual property patents and pending patents related to the conversion of low-cost carbon ore into higher value carbon products as well as exclusive licensing agreements, all of which have a remaining duration of 15-20 years.

Our principal domestic competitors include Alpha Metallurgical Resources, Inc., Blackhawk Mining, LLC, Coronado Global Resources Inc., 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.

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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.

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.

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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.

The adjusted fees proposed in the 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 in August 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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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.

The changes 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.

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The regulations enacted under the Mine Act and MINER Act as well as under similar state acts are routinely expanded or made more stringent, raising compliance costs and increasing potential liability.

For example, MSHA published a request for information in August 2019 related to its consideration of a lower exposure limit for silica in respirable dust.

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.

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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The Patient Protection and Affordable Care Act of 2010 includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and the establishment of a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.

These changes could have a material impact on our costs expended in association with the federal black lung program.

These changes could have a material impact

on our costs expended in association with the federal black lung program.

In addition to possibly incurring liability under federal statutes, we may also be liable under state laws for black lung claims.

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Any reduction in the amount of coal consumed by electric power generators as a result of these limitations could decrease demand for thermal coal.

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

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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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.

The CAA further requires the EPA to periodically review and revise the NAAQS, resulting in the trend of 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.

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● 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 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.

However, this rule will not alter or eliminate the emissions standards established by the MATS rule.

Like CSAPR, MATS and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants.

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.

Like CSAPR, MATS and other similar future regulations could

accelerate the retirement of a significant number of coal-fired power plants.

Such retirements would likely adversely impact our business.

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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.

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

At present, we are principally focused on metallurgical coal production, which is not used in connection with the production of power generation.

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

At the international level, in April 2016, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020.

In November 2019, plans were formally announced for the U.S.

to withdraw from the Paris Agreement with an effective exit date in November 2020.

In February 2021, the current administration announced reentry of the U.S.

into the Paris Agreement along with a new “nationally determined contribution” for U.S.

GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030.

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

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.

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 aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector.

Forty-six 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.

Most recently, at the 27th conference of parties (“COP27”), President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

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.

Congress and may be proposed or adopted in the future.

The likelihood of such legislation has increased due to the change in the administration.

The $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events, and clean energy and transportation investments.

In August 2022, President Biden signed the Inflation Reduction Act of 2022 into law.

The Inflation Reduction Act of 2022 also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change.

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, 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.

For example, in August 2015, the EPA finalized the

Clean Power Plan (the “CPP”) to cut carbon emissions from existing power plants, which did not formally go into effect because the Supreme Court stayed its implementation in February 2016.

In July 2019, the EPA adopted the Affordable Clean Energy Rule (the “ACE Rule”) that repealed and replaced the CPP.

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 January 2021.

In February 2021, the EPA issued a memorandum stating the agency’s position that neither the Clean Power Plan nor the ACE Rule are in effect, and future regulation of carbon dioxide emissions from existing power generation facilities remains uncertain.

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.

The Inflation Reduction Act of 2022 also provides significant funding for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change.

Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures.

The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes;

climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook;

climate-related targets, goals and transition plan (if any);

certain climate-related financial statement metrics in a note to their audited financial statements;

Scope 1 and Scope 2 GHG emissions;

and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions.

Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

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

Various states and regions have also adopted GHG initiatives and certain governmental bodies, have imposed, or are considering the imposition of, fees or taxes based on the emission of GHGs by certain facilities.

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 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.

Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties.

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.

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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.

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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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.

The EPA is undergoing a rulemaking process to redefine the definition of WOTUS, which could be impacted by the U.S.

Supreme Court’s upcoming decision in Sackett v.

EPA , a case regarding the proper test in determining whether wetlands qualify as WOTUS.

A final rule, known as “Rule 1” was announced by the EPA and the Corps in December 2022.

The EPA and Corps are expected to propose a second rule, known as “Rule 2,” further refining Rule 1 by November 2023 and issue a final rule by July 2024.

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.

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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, 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.

In January 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 the proposed denial of closure deadline extensions due to failure of a permittee to demonstrate compliance with coal combustion residuals rules – the EPA took final action to deny the request in November 2022) 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 provided 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.

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Other species in the vicinity of our operations may have their listing status reviewed in the future and could also become protected under the ESA.

In addition, the USFWS has identified bald eagle habitat in some of the counties where we operate.

In addition, the USFWS has identified bald eagle habitats in some of the counties where we operate.

The Bald and Golden Eagle Protection Act prohibits taking certain actions that would harm bald or golden eagles without obtaining a permit from the USFWS.

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.

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.

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.

There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take measures which may adversely impact our business or operations.

Use of Explosives.

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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.

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.

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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.

On July 16, 2020, the Council on Environmental Quality (“CEQ”) revised NEPA’s implementing regulations to make the NEPA process more efficient, effective, and timely.

The rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021).

These regulations are subject to ongoing litigation in several federal district courts, and in October 2021, CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases.

Phase I of CEQ’s proposed rulemaking process was finalized on April 20, 2022, and generally restored provisions that were in effect prior to 2020.

It is anticipated that Phase II of the proposed rulemaking will propose further revisions to ensure the NEPA process “provides for efficient and effective environmental reviews,” and meets environmental, environmental justice, and climate change objectives.

These rules 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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Demand for metallurgical coal is generally more heavily influenced by other factors such as the general economy, interest rates and commodity prices.

Cybersecurity Risk Management

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, and perform other activities related to our business.

Inherent in the use of these technologies is the risk of cyber intrusions, denial of service attacks, and other potential cyber misconduct.

The Company has taken a balanced approach to help minimize cyber risk exposure, which includes the development of an incident response team, performing due diligence on third parties, and conducting response team exercises and system-wide cybersecurity testing.

Human Capital Resources

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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.

We had 725 employees as of December 31, 2022, including our named executive officers, and nearly all of our employees are full-time employees.

None of our employees are covered by collective bargaining agreements, and we have not experienced any strikes or work stoppages related to labor relation issues.

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.

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

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.

We plan to continue to use the services of many of these contractors and consultants.

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● Safety Audits .

We conduct periodic safety audits that include work place examinations, including observation of workers at work, as well as safety program reviews.

We conduct periodic safety audits that include workplace examinations, including observation of workers at work, as well as safety program reviews.

Both internal and external resources are utilized to conduct these audits.

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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 (the “Sarbanes-Oxley Act”);

● 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 of 2010 (the “Dodd-Frank Act”);

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

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.

We ceased being an emerging growth company on December 31, 2022, which was the last day of the fiscal year following the fifth anniversary of our initial public offering.

An auditor’s attestation 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 (the “Sarbanes-Oxley Act”) is included in this report.

Available Information

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We promptly make available on this website, free of charge, the reports that we file or furnish with the Securities and Exchange Commission (“SEC”), corporate governance information (including our Code of Conduct and Ethics) and press releases.

Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at www.sec.gov.

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