UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
Amendment No. 1
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number:
(Exact name of registrant as specified in its charter)
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(State or other jurisdiction |
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(Address of principal executive offices) |
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(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered on which registered | ||
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically, if any, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ☐ | Accelerated filer | ☐ |
☒ | Smaller reporting company | ||
Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued is audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
As of June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of common stock held by non-affiliates of the registrant was $
As of March 29, 2022, the registrant had
Documents Incorporated by Reference:
Certain information required to be furnished pursuant to Part III of this Annual Report on Form 10-K is set forth in, and is hereby incorporated by reference herein from, the definitive proxy statement for our 2022 Annual General Meeting of Stockholders, to be filed by Ramaco Resources with the Securities and Exchange Commission pursuant to Regulation 14A within 120 days after December 31, 2021.
Explanatory Note
We are also including currently dated certifications by our principal executive officer and principal financial officer as Exhibits 31.1 and 31.2 under Section 302 of the Sarbanes-Oxley Act of 2002, as required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In addition, we are including currently dated technical report summaries as Exhibits 96.1 and 96.2.
Other than as expressly set forth above and except with respect to certain conforming changes made to our exhibit index, this Amendment does not, and does not purport to, update or restate the information in the Original 10-K or reflect any events that have occurred after the Original 10-K. Moreover, the information in this Amendment does not update or otherwise affect the financial statements filed as part of the Original 10-K. This Amendment should be read in conjunction with the Original 10-K and our other filings with the SEC.
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PART I
Item 1. Business
Ramaco Resources, Inc. is a Delaware corporation formed in October 2016. 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. As used herein, “Ramaco Resources,” “we,” “our,” and similar terms include Ramaco Resources, Inc. and its subsidiaries, unless the context indicates otherwise.
General
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 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: 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 20,200 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 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 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.
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Metallurgical Coal Industry
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.
U.S. 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. The U.S. is the second largest global supplier to the seaborne metallurgical coal market behind Australia. U.S. 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). U.S. 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. 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 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 the primary element which remains when the volatiles are released.
Our Strategy
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 39 million and 769 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 may also acquire additional reserves or infrastructure that contribute to our focus on advantaged geology and lower costs.
Being a Low-Cost U.S. Producer of Metallurgical Coal. Our reserve base presents advantaged geologic characteristics such as relatively thick coal seams at the deep mines, a low effective mining ratio at the surface mines, and desirable metallurgical coal quality. These characteristics contribute to a production profile that has a cash cost of production that is significantly below most U.S. metallurgical coal producers.
Maintaining a conservative capital structure and prudently managing the business for the long term. We are committed to maintaining a conservative capital structure with a reasonable amount of debt that will afford us the financial flexibility to execute our business strategies on an ongoing basis.
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Enhancing Coal Purchase Opportunities. Depending on market conditions, we purchase coal from other independent producers. Purchased coal is complementary from a blending standpoint with our produced coals or it may also be sold as an independent product.
Demonstrating Excellence in Safety and Environmental Stewardship. We are committed to complying with both regulatory and our own high standards for environmental and employee health and safety requirements. We believe that business excellence is achieved through the pursuit of safer and more productive work practices.
Our Projects
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:
Elk Creek Mining Complex
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. Nearly all our seams contain high-quality, high-volatile metallurgical coal accessible at or above drainage. 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 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. Our market for Elk Creek production is principally North American coke and steel producers. We also market our coal to European, South American, Asian and African customers, and occasionally to coal traders and brokers for use in filling orders for
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their blended products. Additionally, we seek to market a portion of our coal in the specialty coal markets that value low ash content.
We process our Elk Creek coal production through a 700 raw ton-per-hour preparation plant. The plant has a large-diameter (48”) heavy-media cyclone, dual-stage spiral concentrators, froth flotation, horizontal vibratory and screen bowl centrifuges. Our rail load-out facilities at Elk Creek are capable of loading 4,000 tons per hour and a full 150-car unit train in under four hours. The load-out facility is served by the CSX railroad. We also have the ability to develop on controlled property a rail-loading facility on the Norfolk Southern railroad, which would facilitate dual rail service. 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. 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 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. This leased property became available after the former base lease with another party was terminated. The prior lessee, who controlled the property since 1978, did not produce commercial amounts of coal from the property during their possession of the lease. 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 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 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. 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. 4 seam. 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.
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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.
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.
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.
Knox Creek
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-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 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 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.
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
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high quality, mid-vol coal in 2022. We expect Big Creek to be able to produce at these levels for approximately three years.
RAM Mine
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. Operation of our RAM Mine coal reserve may require access to a newly constructed preparation plant and loading facility, third party processing, or direct shipment of raw coal product. Upon commencement of mining, we anticipate that the mine will produce at an annualized rate of between 300 and 500 thousand tons with an estimated 10-year mining life.
We expect that coal from the RAM Mine coal reserve will be transported to our customers by highway trucks, rail cars or by barge on river systems. In addition to close proximity to river barge facilities, our RAM Mine operations are also near Norfolk Southern rail access.
Our RAM Mine property initial production is subject to a final mining permit being issued and market conditions warrant development.
Customers and Contracts
Coal prices differ substantially by region and are impacted by many factors including the overall economy, demand for steel, demand for electricity, location, market, quality and type of coal, mine operation costs and the cost of customer alternatives. 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. 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.
We sold 2.3 million tons of coal during 2021. Of this, 51% was sold to North American markets and 49% was sold into export markets, excluding Canada. 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. 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. The names of the seams in which we have coal reserves, and attributes thereof, are widely recognized in the metallurgical coal market.
Competition
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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Suppliers
Supplies used in our business include petroleum-based fuels, explosives, tires, conveyance structure, ventilation supplies, lubricants and other raw materials as well as spare parts and other consumables used in the mining process. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We believe adequate substitute suppliers and contractors are available, and we are not dependent on any one supplier or contractor. We continually seek to develop relationships with suppliers and contractors that focus on reducing our costs while improving quality and service.
Environmental, Health and Safety and Other Regulatory Matters
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. Expenditures relating to environmental compliance are a major cost consideration for our operations and safety and compliance is a significant factor in mine design, both to meet regulatory requirements and to minimize long-term environmental liabilities.
The following is a summary of the various federal and state environmental and similar regulations that have a material impact on our business:
Surface Mining Control and Reclamation Act. 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, 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
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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. 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. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.
Mining Permits and Approvals. Numerous governmental permits and approvals are required for mining operations. 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 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. 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.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators must also submit a reclamation plan for restoring the mined property to its prior condition, productive use or other permitted condition. The conditions of certain permits also require that we obtain surface owner consent if the surface estate has been split from the mineral estate. This requires us to negotiate with third parties for surface access that overlies coal we acquired or intend to acquire. These negotiations can be costly and time-consuming, lasting years in some instances, which can create additional delays in the permitting process. If we cannot successfully negotiate for land access, we could be denied a permit to mine coal we already own.
Finally, we typically submit necessary mining permit applications several months, or even years, before we anticipate mining a new area. However, we cannot control the pace at which the government issues permits needed for new or ongoing operations. For example, the process of obtaining CWA permits can be particularly time-consuming and subject to delays and denials. The Environmental Protection Agency (the “EPA”) also has the authority to veto permits issued by the U.S. Army Corps. 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. There is some risk that not all existing permits will be approved for renewal, or that existing permits will be approved for renewal only upon terms that restrict or limit our operations in ways that may be material.
Financial Assurance. 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. The changes
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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, 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 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.
We use surety bonds, trusts and letters of credit to provide financial assurance for certain transactions and business activities. Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs and other miscellaneous obligations. The bonds are renewable on a yearly basis. Surety bond rates have increased in recent years and the market terms of such bonds have generally become less favorable. Sureties typically require coal producers to post collateral, often having a value equal to 40% or more of the face amount of the bond. As a result, we may be required to provide collateral, letters of credit or other assurances of payment in order to obtain the necessary types and amounts of financial assurance. Under our surety bonding program, we are not currently required to post any letters of credit or other collateral to secure the surety bonds; obtaining letters of credit in lieu of surety bonds could result in a significant cost increase. Moreover, the need to obtain letters of credit may also reduce amounts that we can borrow under any senior secured credit facility for other purposes. If, in the future, we are unable to secure surety bonds for these obligations and are forced to secure letters of credit indefinitely or obtain some other form of financial assurance at too high of a cost, our profitability may be negatively affected.
We intend to maintain a credit profile that precludes the need to post collateral for our surety bonds. Nonetheless, our surety has the right to demand additional collateral at its discretion.
Some international customers require new suppliers to post performance guarantees during the initial stages of qualifying to become a long-term supplier. To date we have not had to provide a performance guarantee, but it is possible that such a guarantee could be required in the future.
Mine Safety and Health. 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. 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. The various requirements mandated by federal and state statutes, rules, and regulations place restrictions on our methods of operation and result in fees and civil penalties for violations of such requirements or criminal liability for the knowing violation of such standards, significantly impacting operating costs and productivity.
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
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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.
In addition, government inspectors have the authority to issue orders to shut down our operations based on safety considerations under certain circumstances, such as imminent dangers, accidents, failures to abate violations, and unwarrantable failures to comply with mandatory safety standards. If an incident were to occur at one of our operations, it could be shut down for an extended period of time, and our reputation with prospective customers could be materially damaged. 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 Occupational Disease. We are insured for workers’ compensation benefits for work related injuries that occur within our United States operations. 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. State workers’ compensation acts typically provide for an exception to an employer’s immunity from civil lawsuits for workplace injuries in the case of intentional torts. However, West Virginia’s workers’ compensation act provides a much broader exception to workers’ compensation immunity. The exception allows an injured employee to recover against his or her employer where he or she can show damages caused by an unsafe working condition of which the employer was aware that was a violation of a statute, regulation, rule or consensus industry standard. 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 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.
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. In addition to possibly incurring liability under federal statutes, we may also be liable under state laws for black lung claims.
Clean Air Act. The CAA and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter such as fugitive dust. 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 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, 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. |
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| 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 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. 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. Title IV of the CAA requires reductions of sulfur dioxide emissions by electric utilities and applies to all coal-fired power plants generating greater than 25 megawatts of power. Affected power plants have sought to reduce sulfur dioxide emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emission allowances. These reductions could impact our customers in the electric generation industry. These requirements are not supplanted by CSAPR. |
| ● | NAAQS for Criterion 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 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. 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 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. Such retirements would likely adversely impact our business. |
Global Climate Change. Climate change continues to attract considerable public and scientific attention. 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. First, the end use of our coal by our customers in electricity generation, coke plants, and steelmaking is a source of GHGs. Second, combustion of fuel 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 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.
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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.
At present, we are principally focused on metallurgical coal production, which is not used in connection with the production of power generation. However, we may seek to sell greater amounts of our coal into the power-generation market in the future. 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. 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. 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. 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. The D.C. 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. 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
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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.
Clean Water Act. The CWA and corresponding state laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. 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. NWPs are designed to allow for an expedited permitting process, while individual permits involve a longer and more detailed review process. 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. 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. NPDES permits include effluent limitations for discharged pollutants and other terms and conditions, including required monitoring of discharges. 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. 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. Likewise, the water quality of certain receiving streams requires an anti-degradation review before approving any discharge permits. TMDL regulations and anti-degradation policies may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits. In addition, in certain circumstances private citizens may challenge alleged violations of NPDES permit limits in court. Recently, certain citizen groups have filed lawsuits alleging ongoing discharges of pollutants, including selenium and conductance, from valley fills located at certain mining sites in some of the regions where we operate. In West Virginia, several of these cases have been successful for the challengers. While it is difficult to predict the outcome of any potential or future suits, such litigation could result in increased compliance costs following the completion of mining at our operations.
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. 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.
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Resource Conservation and Recovery Act. 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, 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 the 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 the RCRA. Any change or reclassification of this exemption could significantly increase our coal mining costs.
Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances into the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on hazardous substance generators, site owners, transporters, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the primary hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate or that we or our predecessors have previously owned, leased or operated, and sites to which we or our predecessors sent hazardous substances. These liabilities could be significant and materially and adversely impact our financial results and liquidity.
Endangered Species and Bald and Golden Eagle Protection Acts. The ESA and similar state legislation protect species designated as threatened, endangered or other special status. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSMRE and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. Several species indigenous to the areas in which we operate area protected under the ESA. 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. 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. These
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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. Our surface mining operations are subject to numerous regulations relating to blasting activities. Due to these regulations, we will incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to various regulatory requirements. For example, the Department of Homeland Security requires facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) to complete a screening review. Our mines are low risk, Tier 4 facilities which are not subject to additional security plans. The adoption of future, more stringent standards related to the use of explosives could materially adversely impact our cost or ability to conduct our mining operations.
National Environmental Policy Act. 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 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. We are required to comply with numerous other federal, state, and local environmental laws and regulations in addition to those previously discussed. These additional laws include but are not limited to the Safe Drinking Water Act, the Toxic Substances Control Act, and the Emergency Planning and Community Right-to-Know Act. Each of these laws can impact permitting or planned operations and can result in additional costs or operational delays.
Seasonality
Our primary business is not materially impacted by seasonal fluctuations. Demand for metallurgical coal is generally more heavily influenced by other factors such as the general economy, interest rates and commodity prices.
Human Capital Resources
We believe our employees are a competitive advantage. 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. 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
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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.
Safety Philosophy. We have a comprehensive health and safety program based on the core belief that all accidents and occupational illnesses are preventable. We believe that:
| ● | Business excellence is achieved through the pursuit of safer and more productive work practices. |
| ● | Any task that cannot be performed safely should not be performed. |
| ● | Working safely is a requirement of our employees. |
| ● | Controlling the work environment is important, but human behavior within the work environment is paramount. |
| ● | Safety starts with individual decision-making—all employees must assume a share of responsibility for acts within their control that pose a risk of injury to themselves or fellow workers. |
| ● | All levels of the organization must be proactive in implementing safety processes that promote a safe and healthy work environment. |
| ● | Consequently, we are committed to providing a safe work environment; providing our employees with proper training and equipment; and implementing safety and health rules, policies and programs that foster safety excellence. |
Our safety program includes a focus on the following:
| ● | Hiring the Right Workers. Our hiring program includes significant pre-employment screening and reference checks. |
| ● | Safety Incentives. We have a compensation system that encourages and rewards excellent safety performance. |
| ● | Communication. We conduct regular safety meetings with the frequent involvement of senior management to reinforce the “tone at the top.” |
| ● | Drug and Alcohol Testing. We require pre-employment drug screening as well as regular random drug testing that exceeds regulatory requirements. |
| ● | Continuous Improvement Programs. We track key safety performance metrics, including accident rates, violation types and frequencies. We have specific targets in these areas and we measure performance against these targets. Specific action plans are implemented for targeted improvement in areas where performance falls below our expectations. |
| ● | Training. Our training program includes comprehensive new employee orientation and training, annual refresher training and task training components. These training modules are designed to reinforce our high safety expectations. Work rules and procedures are a key element of this training. |
| ● | Accident Investigation. We have a structured accident investigation procedure that identifies root causes of accidents as well as actions necessary to prevent reoccurrence. We focus on near misses and close calls as a means of attempting to prevent more serious accidents from occurring. |
| ● | Safety Audits. We conduct periodic safety audits that include work place examinations, including observation of workers at work, as well as safety program reviews. Both internal and external resources are utilized to conduct these audits. |
| ● | Employee Performance Improvement. A key element of our safety program is the recognition that safe work practices are a requirement of employment. We identify employee performance which is below expectations and develop specific action plans for improvement. |
| ● | Employee Involvement. The key to excellent safety is employee involvement and engagement. We foster direct employee involvement in a number of ways including audit participation, accident investigations, as training resources and through solicitation of ideas in small group meetings and through anonymous workplace observation suggestion boxes. |
| ● | Positive Reinforcement. Establishing safety as a core belief is paramount to our safety performance. As a result, we look for opportunities to celebrate accomplishments and to build pride in our operational safety and performance. |
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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”); or |
| ● | 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.
Available Information
Our investor relations website is ir.ramacoresources.com and we encourage investors to use it as a way of easily finding information about us. 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.
Item 2. Properties
Summary Overview of Mining Operations
Information concerning our mining properties in this Annual Report has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral resources, in addition to our mineral reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.
As used in this Annual Report, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the indicated and measured mineral resources can be the basis of an economically viable project. You are specifically cautioned not to assume that any part or all of the mineral resources will ever be converted into mineral reserves, as defined by the SEC. See “Item 1A “Risk Factors”
You are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have a too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of
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exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, you are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category. Likewise, you are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See “Item 1A “Risk Factors”
The information that follows relating to the Elk Creek Complex and the Berwind/Knox Creek complex (the “Berwind/Knox Creek Complex”) is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRS”) relating to such properties prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS’s, incorporated herein by reference and made a part of this Annual Report.
The following map shows the location of our mining properties and offices, as of December 31, 2021:
At December 31, 2021, we had three mining properties, as summarized in the table below:
| Produced | Produced | Produced |
| ||||||||||||||||
Controlled | (000) | (000) | (000) | Processing Facilities - | ||||||||||||||||
Property |
| Location |
| Acres |
| (years) |
| Stage |
| 2019 |
| 2020 |
| 2021 |
| Mine Type |
| Quality |
| Transportation |
Elk Creek Complex |
| Logan, Wyoming and Mingo Counties, WV |
| 20,200 | 20+ | Production | 1,669 | 1,548 | 1,981 | Underground, Highwall, Surface |
| High Volatile A, A/B, B |
| Elk Creek Preparation Plant - CSX RR, Truck | ||||||
Berwind Complex |
| McDowell County, WV, Buchanan, Russell and Tazewell Counties, VA |
| 103,400 | 20+ | Production | 188 | 147 | 226 | Underground, Highwall, Surface |
| Low, Mid and High Volatile A |
| Knox Creek Preparation Plant - Truck, Norfolk Southern RR | ||||||
RAM Mine |
| Washington County, PA |
| 1,567 | 10 | Development | 0 | 0 | 0 | Underground |
| High Volatile C |
| Truck, Barge | ||||||
Total |
|
|
| 125,167 |
|
|
| 1,857 | 1,695 | 2,207 |
|
|
|
|
|
At December 31, 2021, we owned or controlled, primarily through long-term leases, approximately 123,600 acres of coal in Virginia and West Virginia and 1,567 acres of coal in Pennsylvania. The aggregate annual production for our
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properties during the three most recently completed fiscal years are as follows: 2.2 million tons for fiscal year 2021, 1.7 million tons for fiscal year 2020 and 1.9 million tons for fiscal year 2019. Our preparation plants and loadout facilities are located on properties owned by us or held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Many of these leases provide for a royalty payment to the lessor based on a specific price per ton of coal extracted or as a percentage of coal sales revenue. We believe that all of our leases were entered into at market terms.
Our executive headquarters occupies leased office space in Lexington, Kentucky and we lease office space in Charleston, West Virginia as an operations center. See Item 1. “Business - Our Projects” for specific information about our mining operations.
We hold numerous environmental and mineral extraction permits, water rights and other permits, licenses and approvals from governmental authorities authorizing operations at each of our facilities. With respect to each facility at which we produce coal, permits, licenses and approvals are obtained as needed in the normal course of business based on our mine plans and federal, state, and local regulatory provisions regarding mine permitting and licensing. Based on our historical permitting experience, we expect to be able to continue to obtain necessary mining permits and approvals to support historical rates of production.
We are the operators of the mining and processing operations and the mining methods we use consist of surface, underground and highwall mining methods. The mining operations for the Elk Creek Complex and the Berwind/Knox Creek Complex are material to our business and are further described below.
Elk Creek Complex
The Elk Creek Complex is located approximately 45 miles south of Charleston, West Virginia, in Logan, Wyoming, and Mingo Counties at N 37.698718, W 81.778297. The nearest town is Man, West Virginia, which is approximately five miles to the northwest of the Elk Creek Complex. The Elk Creek Complex is within the Southern West Virginia coal field of the Central Appalachia Coal Producing Region (the “CAPP Region”) of the United States.
Companies that previously mined on the Elk Creek Complex include Island Creek Coal Company (“Island Creek”) which started mining in the area in December 1904. Consolidation Coal Company, now known as Consol Energy, Inc. (“Consol”), bought Island Creek in July 1993 and continued operations in and around the area until the late-1990s when Consol idled its Elk Creek Mine. Ramaco Coal bought the property from Consol in 2012 and started production on the Elk Creek Complex in the fourth quarter of 2016. The 2012 purchase included acquisition of rail access, permitted impoundment and coal refuse disposal facilities, as well as numerous reclaimed, but permitted deep mines. Pittston Coal Company operated mines on the northern Huff Creek portion (McDonald and Baisden properties) of the Elk Creek Complex in the 1970s and 1980s before the company exited the coal mining business in 2001.
The Elk Creek Complex consists of approximately 20,200 acres of leased coal holdings. Within the Elk Creek Complex controlled coal holdings, 16,000 acres lie in Logan County, 2,800 acres in Wyoming County and 1,400 acres in Mingo County. The Elk Creek Complex is in the production stage and currently has four active mines, five planned and permitted mines, one permitted inactive mine, and one planned but not permitted mine. The five planned and permitted mines include two contour surface mine developing areas for a highwall miner, and three underground room and pillar mines, which use continuous miners for mine development. Ramaco began production of metallurgical coal at the complex in 2016. A majority of the underground mines implement retreat mining, which results in mining recovery of greater than 80 percent. Contour mining has an average mining recovery of approximately 90 percent, and the highwall mines have and average mining recovery of approximately 40 percent.
The Elk Creek Complex is mining several seams and seam splits, including the Chilton A, Upper Dorothy, Upper Dorothy 2, 3, and 4, Middle Dorothy, Lower Dorothy, Upper Cedar Grove, Lower Cedar Grove A, Lower Cedar Grove B, Lower Cedar Grove C, No. 2 Gas, Upper Alma, Lower Alma, Powellton, and Eagle seams.
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Currently, there are four active mines within the complex:
| ● | Ram No. 1 Surface and Highwall Mine; |
| ● | Stonecoal No. 2 Alma Deep Mine; |
| ● | Rockhouse Eagle Deep Mine; and |
| ● | No. 2 Gas Deep Mine. |
There are five planned and permitted mines within the complex:
| ● | Michael Powellton Deep Mine, scheduled for late-2022 startup; |
| ● | Crucible Lower Cedar Grove B and C seams, scheduled for early-2022 startup; |
| ● | Ram No. 3 Surface and Highwall Mine, scheduled for 2023 startup; |
| ● | Ram No. 2 Surface and Highwall Mine (which is the extension of Ram No. 1 above), scheduled for 2023 startup; and |
| ● | Glenalum Tunnel #1 Deep Mine, scheduled for 2027 startup. |
There is one permitted inactive mine, the Eight-Kay Deep Mine that is projected to start in 2027 and the Bens Creek Deep Mine is planned but is not yet permitted. The projected startup date for this mine is 2026. There are several other resource areas on the property which Ramaco may plan to mine and permit at a future date.
The current Elk Creek Complex Life-of-Mine (“LOM”) Plan projects mining through 2040; an expected mine life for the complex of 19 years. Ramaco projects total annual mine production to range from 2.0 to 2.6 million clean tons when the surface and continuous miner units are operating (2022 through 2028) and 0.5 to 1.6 million clean tons per year from 2029 through 2040 after surface mining ceases in 2028, in the absence of new mine development. It is likely future mines will be planned and scheduled, as necessary, from resource areas within the complex, to meet internal Ramaco production goals aligned with market conditions.
All Run-of-Mine (“ROM”) coal is washed at the Elk Creek Preparation Plant. The Elk Creek Preparation Plant, built in 2017 by Raw Resources Group located in Princeton, West Virginia, is a well designed and constructed preparation plant, with ROM processing capacity of 700 tons per hour.
The book value of the Elk Creek Complex property and its associated plant and equipment was $186 million as of December 31, 2021. The Elk Creek Complex utilizes industry standard, modern surface and underground mining equipment, processing equipment and infrastructure that is in good operating condition and capable of meeting planned production requirements using prudent operating methods and operating schedules.
The Elk Creek Complex produces a high quality, high-volatile metallurgical coal. Historically, the market for metallurgical coal from the Elk Creek Complex has been domestic metallurgical coal consumers and the global seaborne metallurgical coal market. Coal produced from the complex is primarily high-volatile A and high-volatile B metallurgical coal. The Elk Creek Complex also produces thermal coal and specialty coals, which represent approximately five percent of sales.
Volatiles refers to the volatile matter contained in the coal. Classification of coal as low, mid or high-volatile refers to the specific volatile content within the coal, with coals of 17% to 22% volatile matter being classified as low-volatile, 23% to 31% as mid volatile and 32% or greater as high-volatile. The volatile matter in coal impacts coke yield (i.e. the amount of coke and coke by-products produced per ton of coal charged). Low-volatile coal contains more carbon, but too much carbon can result in coke oven damage. Too much volatile matter results in less carbon and reduces the volume of coke produced. Therefore, coke producers use blends of high-volatile and low-volatile coals for coke production.
We are unaware of any significant encumbrances to the Elk Creek Complex, including current and future permitting requirements and associated timelines, permit conditions, and violations and fines.
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Berwind/Knox Creek Complex
The Berwind/Knox Creek Complex consists of three general properties or areas as follows:
| ● | Berwind Property; |
| ● | Big Creek Property; and |
| ● | Knox Creek Property. |
The Berwind/Knox Creek Complex is located approximately 80 miles south of Charleston, West Virginia; 100 miles west of Roanoke, Virginia; 60 miles northeast of Kingsport, Tennessee; and 160 miles east/southeast of Lexington, Kentucky at N 37.164522, W 81.744893. The complex includes areas in Buchanan, Russell and Tazewell Counties, Virginia and McDowell County, West Virginia. The Berwind/Knox Creek Complex is within the Southwestern Virginia and Southern West Virginia coal fields of the CAPP Region of the United States.
The Berwind/Knox Creek Complex and surrounding area has an extensive history of coal mining, primarily by underground mining methods. Mining within the Berwind/Knox Creek Complex likely began in the early-1900s and there have been many different mine operators both large and small in the region since then.
The Berwind/Knox Creek Complex consists of approximately 103,400 acres of owned and leased coal holdings. Within the Berwind/Knox Creek Complex controlled coal holdings, 32,500 acres lie in McDowell County, West Virginia, 24,900 acres lie in Buchanan County, Virginia, 30,300 acres in Tazewell County, Virginia, and 15,700 acres in Russell County Virginia. The Berwind/Knox Creek Complex is in the production stage and currently has three active mines and two planned and permitted mines. The three active mines include one contour surface mine developing areas for a highwall miner, and two underground room and pillar mines, which use continuous miners for mine development. Ramaco began production of metallurgical coal at the complex in 2017. A majority of the underground mines implement retreat mining, which results in mining recovery of greater than 80 percent. Contour mining has an average mining recovery of approximately 90 percent, and the highwall mine has an average mining recovery of approximately 40 percent.
The Berwind/Knox Creek Complex is mining several seams and seam splits, including the Pocahontas 4, Pocahontas 3, Jawbone and Tiller seams.
Active Mines:
Planned and Permitted Mines:
We recently acquired the Laurel Fork Deep Mine as part of the purchase of the Amonate Assets, however, geology work has not been completed for this mining property and reserves have not been estimated.
The current Berwind/Knox Creek Complex LOM Plan projects mining through 2039, an expected mine life for the complex of 18 years. Ramaco projects total annual production to range from 0.8 to 1.0 million clean tons when the surface and continuous miner units are operating (2022 through 2023), and 0.4 to 0.8 million clean tons per year from 2024 through 2039 after surface mining ceases in 2023. These figures do not include mining on the Amonate reserves, which we anticipate adding between 0.7-0.9 million tons of annual production by the end of 2023. It is likely future mines will be planned and scheduled, as necessary, from resource areas within the complex, to meet internal Ramaco production goals aligned with market conditions.
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Currently, all ROM coal is washed at the Knox Creek preparation plant. The Knox Creek preparation plant, built in 1981 by Powell Construction Company located in Johnson City, Tennessee, is a well designed and constructed preparation plant, with ROM processing capacity of 750 tons per hour.
The book value of the Berwind/Knox Creek Complex property and its associated plant and equipment is $96 million as of December 31, 2021. The Berwind/Knox Creek Complex utilizes industry standard, modern surface and underground mining equipment, processing equipment and infrastructure that is in good operating condition and capable of meeting planned production requirements using prudent operating methods and operating schedules.
The Berwind/Knox Creek Complex produces primarily a high quality, mid and low-volatile metallurgical coal. Historically, the market for metallurgical coal from the Berwind/Knox Creek Complex has been domestic metallurgical coal consumers and the global seaborne metallurgical coal market. The Berwind/Knox Creek Complex also produces a minimal quantity of thermal coal from the surface mine, which represents approximately two percent of its total coal sales.
We are unaware of any significant encumbrances to the Berwind/Knox Creek Complex, including current and future permitting requirements and associated timelines, permit conditions, and violations and fines.
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Summary of Mineral Resources and Reserves
Summaries of our mineral resources and reserves at December 31, 2021, are set forth in Tables 1 and 2.
Table 1. Summary Mineral Resources at end of Fiscal Year ended December 31, 2021
Measured Mineral Resources | Indicated Mineral Resources | Measured + Indicated | Inferred Mineral Resources | |||||||||||||||||||||
Coal Quality (Dry Basis) Raw | Coal Quality (Dry Basis) Raw | Coal Quality (Dry Basis) Raw | Coal Quality (Dry Basis) Raw | |||||||||||||||||||||
| Amount |
| Ash (%) |
| Relative Density |
| Amount |
| Ash (%) |
| Relative Density |
| Amount |
| Ash (%) |
| Relative Density |
| Amount |
| Ash (%) |
| Relative Density | |
Area | ||||||||||||||||||||||||
Berwind/Knox Creek Complex | ||||||||||||||||||||||||
Berwind Property | 197,215 | 21.80 | 92.20 | 40,825 | 21.80 | 92.20 | 238,040 | 21.80 | 92.20 | 4,495 | 21.80 | 92.20 | ||||||||||||
Big Creek Property | 30,150 | 13.60 | 90.50 | — | — | — | 30,150 | 13.60 | 90.50 | — | — | — | ||||||||||||
Knox Creek Property | 259,035 | 11.30 | 87.70 | 6,765 | 11.30 | 87.70 | 265,800 | 11.30 | 87.70 | — | — | — | ||||||||||||
Elk Creek | ||||||||||||||||||||||||
Ram Surface | 95,250 | 15.74 | 88.65 | 14,055 | 15.74 | 88.65 | 109,305 | 15.74 | 88.65 | — | 15.74 | 88.65 | ||||||||||||
Crucible Deep | 2,285 | 8.74 | 84.04 | 730 | 8.74 | 84.04 | 3,015 | 8.74 | 84.04 | — | 8.74 | 84.04 | ||||||||||||
Stonecoal No. 2 Alma Deep Mine | 24,005 | 15.25 | 87.44 | 5,135 | 15.25 | 87.44 | 29,140 | 15.25 | 87.44 | — | 15.25 | 87.44 | ||||||||||||
Michael Powellton Mine | 2,460 | 32.24 | 97.85 | — | 32.24 | 97.85 | 2,460 | 32.24 | 97.85 | — | 32.24 | 97.85 | ||||||||||||
Rockhouse Eagle Deep Mine | 4,065 | 19.62 | 89.07 | 35 | 19.62 | 89.07 | 4,100 | 19.62 | 89.07 | — | 19.62 | 89.07 | ||||||||||||
Moorfork Mine | 2,390 | 15.49 | 82.24 | 360 | 15.49 | 82.24 | 2,750 | 15.49 | 82.24 | — | 15.49 | 82.24 | ||||||||||||
Bens Creek Deep Mine | 15,510 | 25.83 | 93.81 | 24,425 | 25.83 | 93.81 | 39,935 | 25.83 | 93.81 | — | 25.83 | 93.81 | ||||||||||||
Lower War Eagle | 4,965 | 21.76 | 90.64 | 2,870 | 21.76 | 90.64 | 7,835 | 21.76 | 90.64 | 70 | 21.76 | 90.64 | ||||||||||||
Glenalum Tunnel #1 Deep Mine | 9,295 | 4.80 | 81.13 | 10,855 | 4.80 | 81.13 | 20,150 | 4.80 | 81.13 | 815 | 4.80 | 81.13 | ||||||||||||
Gilbert Deep Mine | 2,085 | 23.56 | 92.66 | 2,565 | 23.56 | 92.66 | 4,650 | 23.56 | 92.66 | 85 | 23.56 | 92.66 | ||||||||||||
Ram | ||||||||||||||||||||||||
Ram Mine | 3,724 | 6.00 | 81.12 | 7,716 | 6.00 | 81.12 | 11,440 | 6.00 | 81.12 | — | — | — | ||||||||||||
Grand Total | 652,434 | 116,336 | 768,770 | 5,465 | ||||||||||||||||||||
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Notes:
| ● | Mineral Resources reported above are not Mineral Reserves and do not meet the threshold for reserve modifying factors, such as estimated economic viability, that would allow for conversion to mineral reserves. There is no certainty that any part of the Mineral Resources estimated will be converted into Mineral Reserves. Mineral Resources reported here are exclusive of Mineral Reserves. |
| ● | Resource probable economic mineability is based on underground minable resources with 2.0 feet minimum seam thickness, surface and highwall mines with 1.0 feet minimum seam thickness, area mining with a cutoff stripping ratio of 20:1, and primarily metallurgical low and mid-volatile coal at the Berwind/Knox Creek Complex realizing a sales price of $142 per ton at a cash cost of $77 per clean ton (FOB Mine) and primarily a metallurgical high-volatile A and high-volatile B coal at the Elk Creek Complex realizing a sales price of $131 per ton at a cash cost of $77 per clean ton (FOB Mine). |
| ● | Numbers in the table have been rounded to reflect the accuracy of the estimate and may not sum due to rounding. |
Table 2. Summary Mineral Reserves at end of Fiscal Year ended December 31, 2021
Proven Mineral Reserves | Probable Mineral Reserves | Proven + Probable Mineral Reserves | ||||||||||||||||
Coal Quality (Dry Basis) Raw | Coal Quality (Dry Basis) Raw | Coal Quality (Dry Basis) Raw | ||||||||||||||||
| Amount |
| Ash (%) |
| Relative Density |
| Amount |
| Ash (%) |
| Relative Density |
| Amount |
| Ash (%) |
| Relative Density | |
Area | ||||||||||||||||||
Berwind /Knox Creek Complex | ||||||||||||||||||
Berwind Property | ||||||||||||||||||
Pocahontas No. 1 Deep Mine | 9,295 | 23.39 | 92.58 | 25 | 23.39 | 92.58 | 9,320 | 23.39 | 92.58 | |||||||||
Triad Pocahontas 4 Deep Mine | 90 | 23.02 | 92.35 | — | — | — | 90 | 23.02 | 93.25 | |||||||||
Knox Creek Property | ||||||||||||||||||
Big Creek Surface and Highwall Mine | 450 | 18.36 | 89.73 | — | — | 89.73 | 450 | 18.36 | 89.73 | |||||||||
Jawbone | 670 | 10.91 | 93.39 | — | — | — | 670 | 10.91 | 93.39 | |||||||||
Elk Creek Complex | ||||||||||||||||||
Ram Surface and Highwall Mine | 1,965 | 15.10 | 87.10 | 35 | 15.10 | 87.10 | 2,000 | 15.10 | 87.10 | |||||||||
Ram Surface 3 and Highwall Mine | 2,760 | 15.80 | 87.80 | 440 | 15.80 | 87.80 | 3,200 | 15.80 | 87.80 | |||||||||
Crucible Deep | 4,305 | 10.40 | 84.10 | 645 | 10.40 | 84.10 | 4,950 | 10.40 | 84.10 | |||||||||
Stonecoal No. 2 Alma Deep Mine | 5,010 | 23.80 | 84.60 | 290 | 23.80 | 84.60 | 5,300 | 23.80 | 84.60 | |||||||||
Michael Powellton Mine | 60 | 42.80 | 104.60 | — | — | — | 60 | 42.80 | 104.60 | |||||||||
Rockhouse Eagle Deep Mine | 2,045 | 16.30 | 87.80 | 495 | 16.30 | 87.80 | 2,540 | 16.30 | 87.80 | |||||||||
No. 2 Gas Deep Mine | 2,085 | 27.90 | 94.40 | 455 | 27.90 | 94.40 | 2,540 | 27.90 | 94.40 | |||||||||
Eight-Kay | 1,390 | 12.30 | 85.70 | 240 | 12.30 | 85.70 | 1,630 | 12.30 | 85.70 | |||||||||
Bens Creek Deep Mine | 1,670 | 28.60 | 95.80 | 170 | 28.60 | 95.80 | 1,840 | 28.60 | 95.80 | |||||||||
Glenalum Tunnel #1 Deep Mine | 2,380 | 5.90 | 81.80 | 2,190 | 5.90 | 81.80 | 4,570 | 5.90 | 81.80 | |||||||||
Grand Total | 34,175 | 4,985 | 39,160 | |||||||||||||||
Notes:
| ● | Clean recoverable reserve tonnage based on underground mining recovery of 50 to 80 percent (contingent upon retreat mining capability), 90 percent for surface mining, 40 percent for highwall mining, theoretical preparation plant yield, and a 95 percent preparation plant efficiency. |
| ● | Mineral Reserves estimated for the Berwind/Knox Creek Complex are based primarily on metallurgical low and mid-volatile coal at the Berwind/Knox Creek Complex realizing a sales price of $142 per ton at a cash cost of $77 per clean ton (FOB Mine) and primarily a metallurgical high-volatile A and high-volatile B coal at the Elk Creek Complex realizing a sales price of $131 per ton at a cash cost of $77 per clean ton (FOB Mine). |
| ● | Numbers in the table have been rounded to reflect the accuracy of the estimate and may not sum due to rounding. |
| ● | Mineral Reserves are reported exclusive of Mineral Resources. |
Our coal resource and reserve estimates at December 31, 2021, were prepared by a qualified person (“QP”) and have a basis in periodic, historical reserve studies completed by third-party geological engineering firms. Our coal resource and reserve estimates are based on data obtained from our drilling activities and other available geologic data. Acquisitions or sales of coal properties will change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. The most recent studies of our coal reserves for the Elk Creek Complex, Berwind/Knox Creek Complex and RAM Mine were prepared by an independent engineering firm, Weir International, Inc. (“Weir”). In periods between third party updates, we update reserves utilizing our internal staff of
27
engineers and geologists based upon production data. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves going forward.
In our most recent reserve studies, Weir prepared our reserve reporting in compliance with the Regulation S-K 1300 requirements. Weir initiated this process with us by completing a historical project review as well as its validation of our complete drill hole database. Weir validated that property control is accurately reflected in reserve modeling, verifying the latest property boundaries, including control by each individual seam. Weir also examined reserve boundaries to ensure agreement with mining parameters, such as minimum thickness, minimum yield and minimum inter-burden between seams. Resource classification is determined based on the expectation of our meeting these mining parameters. Weir also conducted mining integrity checks to ensure each reserve area is minable.
In determining whether our reserves meet this standard, we take into account, among other things, our potential ability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining or renewing mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economic recoverability of our reserves is based on market conditions including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economically recoverable varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economically recoverable at a price in excess of our cash costs to mine the coal and fund our ongoing replacement capital. The reserves in this Annual Report are classified by reliability or accuracy in decreasing order of geological assurance as Proven (Measured) and Probable (Indicated).
Summaries of the Berwind/Knox Creek Complex’s and Elk Creek Complex’s mineral resources and mineral reserves as of December 31, 2021 and December 31, 2020 are shown below. Weir served as the QP and prepared the estimates of mineral resources and mineral reserves at the Berwind/Knox Creek Complex and Elk Creek Complex. A copy of the QP’s TRS with respect to the mineral resource and reserve estimates at the Berwind/Knox Creek Complex, dated February 7, 2022, with an effective date of December 31, 2021 (the “Berwind TRS”), is filed as Exhibit 96.1 and at the Elk Creek Complex, dated February 7, 2022, with an effective date of December 31, 2021 (the “Elk Creek TRS”), is filed as Exhibit 96.2 hereto.
Year ended December 31, | ||||||
| 2021 |
| 2020 | |||
Measured + | Proven + Probable | Proven + Probable | ||||
Indicated In-Place | Clean Recoverable | Clean Recoverable | ||||
(in millions) |
| Resources |
| Reserves |
| Reserves |
Area | ||||||
Berwind/Knox Creek Complex |
| 534 | 10 |
| 144 | |
Elk Creek Complex | 223 | 29 | 113 | |||
Total | 757 | 39 | 257 | |||
The combined measured and indicated resources were previously not reported in the fiscal year ending December 31, 2020 but have been included for fiscal year ending December 31, 2021 as a result of changes in reporting requirements. The combined proven and probable reserves at the Berwind/Knox Creek Complex and the Elk Creek Complex decreased by approximately 92.7 percent and 74.7 percent, respectively. The decreases in proven and probable reserves were primarily the result of changes in determination of reserve classifications under requirements of subpart 1300 of Regulation S-K and to a lesser extent due to acquisition of upper seams at the Berwind property at the Berwind/Knox Creek Complex, acquisition of the Big Creek property at the Berwind/Knox Creek Complex, improved coal sales prices, and depletion from production activity.
Key assumptions and parameters relating to the mineral resources and mineral reserves at the Berwind/Knox Creek Complex and the Elk Creek Complex are discussed in Sections 11 and 12 of the Berwind TRS and the Elk Creek TRS, respectively.
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Internal Controls
In our exploration and mineral resource and reserve estimation efforts, we utilize an American National Standards Institute certified third-party laboratory, which has in-house quality control and assurance procedures. Once in possession of the samples, the laboratory standard sample preparation and security procedures are followed. After the sample has been tested, reviewed, and accepted, the disposal of the sample is done in accordance with local, state and EPA approved methods.
Weir has determined the sample preparation, security and analysis procedures used for our drillhole samples meet current coal industry standards and practices for quality testing, with laboratory results suitable to use for geological modeling, mineral resource estimation and economic evaluation.
Year-end reserve estimates are and will continue to be reviewed by our Chief Executive Officer and other senior management, and revisions are communicated to our board of directors. Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenue or higher than expected costs. Actual production recovered from identified reserve areas and properties, and revenue and expenditures associated with our mining operations, may vary materially from estimates.
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PART II
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID | 31 |
33 | |
34 | |
35 | |
36 | |
37 | |
38 |
30
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Stockholders and the Board of Directors of Ramaco Resources, Inc.
Lexington, Kentucky
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Ramaco Resources, Inc. (the “Company”) as of December 31, 2021, the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021, and the results of its operations and its cash flows for each of the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Information Technology General Controls and Control Environment
Description of Critical Audit Matter
As discussed in Management’s Report on Internal Control Over Financial Reporting, the Company identified a material weakness in their internal control over financial reporting related to ineffective information technology general controls (ITGC’s) in the areas of user access and certain automated and manual business process controls that are dependent on the affected ITGCs (control environment). Based on the ineffective ITGC’s, we identified the performance of the necessary incremental audit procedures over the financial information reliant on the impacted ITGC’s as a critical audit matter.
31
Significant auditor judgment was required to design and execute the incremental audit procedures and to assess the sufficiency of the procedures performed and evidence obtained.
The primary procedures we performed to address the critical audit matter included the following.
| ● | Involving forensic professionals with specialized skills and knowledge in data analysis to perform an evaluation of the journal entry data, vendor master file, and disbursement files. Forensic professionals also assisted with the identification of certain entries that required additional testing and for all such entries, we agreed the journal entry data to source documents. |
| ● | Tested the underlying records of selected transactions and other data discussed above to support the use of the information in the conduct of the audit; and |
| ● | We evaluated the collective results of the incremental audit procedures performed to assess the sufficiency of audit evidence obtained related to the information produced by the impacted IT systems. |
Asset Retirement Obligations
Description of Critical Audit Matter
At December 31, 2021, the Company’s asset retirement obligations (“ARO”) totaled $22.6 million. The Company’s ARO primarily consist of spending estimates, based upon detailed engineering calculations, related to reclaiming metallurgical coal land and support facilities in accordance with federal and state reclamation laws as defined by each mining permit. Legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to development costs, at the time they are incurred. The liability is accreted to its present value each period and the capitalized cost is amortized using the units-of-production method over estimated recoverable reserves upon commencement of mining.
The calculation of reclamation metallurgical coal land and support facilities obligations involve a high degree of subjectivity and auditing the significant assumptions utilized by management in estimating the amount of the liability requires judgment. In particular, the obligation is determined using a discounted cash flow technique and is based upon mining permit requirements and various assumptions including credit-adjusted risk-free rates, inflation rates, estimates of disturbed acreage, timing of reclamation activities, and reclamation costs.
We obtained an understanding of management’s internal controls and evaluated the design of these controls over the Company’s accounting for ARO, including controls over management’s review of the significant assumptions described above. In addition, we evaluated the methodology used by the Company’s specialist and testing the significant assumptions and the underlying data, compared assumptions including the credit-adjusted risk-free rate, and inflation rate to current market data, evaluated significant changes from the prior estimate, verified consistency between timing of reclamation activities and projected mine life, considered the appropriateness of the estimated costs based on mine type, compared anticipated costs to recent operating data, and recalculated management’s estimate. Additionally, we involved our specialists to assist in our assessment of the Company’s ARO liability. As part of this effort, our specialists interviewed members of the Company’s specialist, assessed the completeness of the mine reclamation estimates with respect to meeting mine closure and post closure plan regulatory requirements, and evaluated the reasonableness of the engineering estimates and assumptions.
/s/
We have served as the Company’s auditor since 2022.
March 31, 2022
32
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Ramaco Resources, Inc.
Lexington, Kentucky
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Ramaco Resources, Inc. (the Company) as of December 31, 2020 and the related consolidated statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 2020, and the related notes (collectively referred to as the financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2020, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Briggs & Veselka Co.
We served as the Company’s auditor from 2015 to 2021.
Houston, Texas
February 18, 2021
33
Ramaco Resources, Inc.
Consolidated Balance Sheets
In thousands, except share |
| 2021 |
| 2020 | ||
Assets |
|
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| |||
Current assets |
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|
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Cash and cash equivalents | $ | | $ | | ||
Accounts receivable |
| |
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Inventories |
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Prepaid expenses and other |
| |
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Total current assets |
| |
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Property, plant and equipment, net |
| |
| | ||
Financing lease right-of-use assets, net | | — | ||||
Advanced coal royalties |
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Other |
| |
| | ||
Total Assets | $ | | $ | | ||
Liabilities and Stockholders' Equity | ||||||
Liabilities | ||||||
Current liabilities | ||||||
Accounts payable | $ | | $ | | ||
Accrued expenses |
| |
| | ||
Asset retirement obligations |
| |
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Current portion of long-term debt |
| |
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Current portion of financing lease obligations | | — | ||||
Other current liabilities | | | ||||
Total current liabilities |
| |
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Asset retirement obligations |
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Long-term debt, net |
| |
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Long-term financing lease obligations, net | | — | ||||
Senior notes, net | | — | ||||
Deferred tax liability, net |
| |
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Other long-term liabilities | | | ||||
Total liabilities | |
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Commitments and contingencies |
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Stockholders' Equity | ||||||
Preferred stock, $ |
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Common stock, $ |
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Additional paid-in capital |
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Retained earnings |
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Total stockholders' equity |
| |
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Total Liabilities and Stockholders' Equity | $ | | $ | | ||
The accompanying notes are an integral part of these consolidated financial statements.
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Ramaco Resources, Inc.
Consolidated Statements of Operations
Year ended December 31, | |||||||||
In thousands, except per-share amounts |
| 2021 |
| 2020 |
| 2019 | |||
Revenue |
| $ | |
| $ | |
| $ | |
Costs and expenses | |||||||||
Cost of sales (exclusive of items shown separately below) |
| |
| |
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Asset retirement obligations accretion |
| |
| |
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Depreciation and amortization |
| |
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Selling, general and administrative |
| |
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Total costs and expenses |
| |
| |
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Operating income (loss) |
| |
| ( |
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Other income |
| |
| |
| | |||
Interest expense, net |
| ( |
| ( |
| ( | |||
Income (loss) before tax |
| |
| ( |
| | |||
Income tax expense (benefit) |
| |
| ( |
| | |||
Net income (loss) | $ | | $ | ( | $ | | |||
Earnings (loss) per common share | |||||||||
Basic | $ | | $ | ( | $ | | |||
Diluted | $ | | $ | ( | $ | | |||
Basic weighted average shares outstanding |
| |
| | | ||||
Diluted weighted average shares outstanding |
| |
| | | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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Ramaco Resources, Inc.
Consolidated Statements of Equity
Additional | Retained | Total | ||||||||||
| Common |
| Paid- |
| Earnings |
| Stockholders’ | |||||
In thousands |
| Stock |
| in Capital |
| (Deficit) |
| Equity | ||||
Balance at January 1, 2019 | $ | | $ | | $ | ( | $ | | ||||
Restricted stock surrendered for withholding taxes payable | — | ( | — | ( | ||||||||
Stock-based compensation |
| |
| |
| — |
| | ||||
Net income |
| — |
| — |
| |
| | ||||
Balance at December 31, 2019 | | | | | ||||||||
Restricted stock surrendered for withholding taxes payable | ( | ( | — | ( | ||||||||
Stock-based compensation |
| |
| |
| — |
| | ||||
Net loss |
| — |
| — |
| ( |
| ( | ||||
Balance at December 31, 2020 | | | | | ||||||||
Restricted stock surrendered for withholding taxes payable | ( | ( | — | ( | ||||||||
Stock-based compensation |
| |
| |
| — |
| | ||||
Dividends accrued ($ | — | — | ( | ( | ||||||||
Net income |
| — |
| — |
| |
| | ||||
Balance at December 31, 2021 | $ | | $ | | $ | | $ | | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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Ramaco Resources, Inc.
Consolidated Statements of Cash Flows
Years ended December 31, | |||||||||
In thousands |
| 2021 |
| 2020 |
| 2019 | |||
Cash flows from operating activities: |
|
|
|
|
| ||||
Net income (loss) | $ | | $ | ( | $ | | |||
Adjustments to reconcile net income (loss) to net cash from operating activities: | |||||||||
Accretion of asset retirement obligations |
| |
| |
| | |||
Depreciation and amortization |
| |
| |
| | |||
Amortization of debt issuance costs |
| |
| |
| | |||
Stock-based compensation |
| |
| |
| | |||
Other income - employee retention tax credit | ( | — | — | ||||||
Other income - PPP Loan | — | ( | — | ||||||
Deferred income taxes |
| |
| ( |
| | |||
Changes in operating assets and liabilities: | |||||||||
Accounts receivable |
| ( |
| ( |
| ( | |||
Prepaid expenses and other current assets |
| |
| |
| | |||
Inventories |
| ( |
| |
| ( | |||
Other assets and liabilities |
| |
| ( |
| | |||
Accounts payable |
| ( |
| |
| ( | |||
Accrued expenses |
| |
| ( |
| | |||
Net cash from operating activities |
| |
| |
| | |||
Cash flow from investing activities: | |||||||||
Purchases of property, plant and equipment |
| ( |
| ( |
| ( | |||
Acquisition of Amonate assets | ( | — | — | ||||||
Net cash from investing activities | ( | ( | ( | ||||||
Cash flows from financing activities: | |||||||||
Proceeds from PPP Loan | — | | — | ||||||
Proceeds from borrowings |
| |
| |
| | |||
Payments of debt issuance cost | ( | — | — | ||||||
Repayment of borrowings |
| ( |
| ( |
| ( | |||
Repayments of financed insurance payable | ( | ( | ( | ||||||
Repayments of financing leased equipment | ( | — | — | ||||||
Restricted stock surrendered for withholding taxes payable | ( | ( | ( | ||||||
Net cash from financing activities |
| |
| |
| | |||
Net change in cash and cash equivalents and restricted cash |
| |
| ( |
| ( | |||
Cash and cash equivalents and restricted cash, beginning of period |
| |
| |
| | |||
Cash and cash equivalents and restricted cash, end of period | $ | | $ | | $ | | |||
Supplemental cash flow information: | |||||||||
Cash paid for interest | $ | | $ | | $ | | |||
Cash paid for taxes |
| |
| |
| ||||
Non-cash investing and financing activities: | |||||||||
Leased assets obtained under new financing leases |
| |
| — |
| — | |||
Dividend accrued not paid | | — | — | ||||||
Capital expenditures included in accounts payable and accrued expenses |
| |
| |
| | |||
Financed insurance |
| |
| |
| | |||
Additional asset retirement obligations incurred |
| |
| |
| | |||
The accompanying notes are an integral part of these consolidated financial statements.
37
Ramaco Resources, Inc.
Notes to Consolidated Financial Statements
NOTE 1—DESCRIPTION OF BUSINESS
Ramaco Resources, Inc. (“Ramaco”) is a Delaware corporation formed in October 2016. Our principal corporate offices are located in Lexington, Kentucky. We are an operator and developer of high-quality, low-cost metallurgical coal in southern West Virginia, southwestern Virginia, and southwestern Pennsylvania.
As used herein, “the Company,” “we,” “us,” “our,” and similar terms include Ramaco Resources, Inc. and its subsidiaries, unless the context indicates otherwise.
Our development portfolio includes
We operate
COVID-19 Pandemic—The global spread of COVID-19 created significant volatility, uncertainty and economic disruption during 2020. The Company was adversely affected by the deterioration and increased uncertainty in the macroeconomic outlook as a result of the impact of COVID-19. After the initial outbreak, we observed a declining demand for, and declines in the spot price of, metallurgical coal as business and consumer activity decelerated across the globe. Throughout 2021, we saw increases in demand from our primary customers, as the global economic recovery began. U.S. steel prices also have increased significantly due to this recovery and the effects from large-scale government stimulus measures.
We continue to actively monitor the situation and may take further actions altering our business operations that we determine are in the best interests of our employees, customers, suppliers, and stakeholders, or as required by federal, state, or local authorities.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Consolidation—The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and U.S. Securities and Exchange Commission regulations. The financial statements are presented on a consolidated basis for all periods presented. All significant intercompany balances and transactions between consolidated entities have been eliminated in consolidation.
Use of estimates—The preparation of these financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect certain reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates are related to the quantity and value of coal inventories, stock-based compensation, asset retirement
38
obligations, occupational disease obligations, evaluation of long-lived assets for impairment, and the quantities and values of coal reserves.
Revenue Recognition—Our primary source of revenue is from the sale of coal through contracts with steel producers usually having durations of less than one year. Revenue is recognized when performance obligations under the terms of a contract with our customers are satisfied. This occurs when control of the coal is transferred to our customers. For coal shipments to domestic customers via rail, control is generally transferred when the railcar is loaded. Control is transferred for export coal shipments to customers via ocean vessel when the vessel is loaded at the port.
Our coal sales generally include up to 90-day payment terms following the transfer of control of the goods to our customer. In the case of some of our foreign customers, our contracts also require that letters of credit are posted to secure payment of any outstanding receivable. We do not include extended payment terms in our contracts. Our contracts with customers typically provide for minimum specifications or qualities of the coal we deliver. Variances from these specifications or qualities are settled by means of price adjustments. Generally, these price adjustments are settled within 30 days of delivery and are insignificant.
Freight Revenue and Expense—Costs incurred to transport coal to the point of sale at the port facility are included in cost of sales and the gross amounts billed to customers to cover shipping to and handling of the coal at the port are included in revenue.
Cash and Cash Equivalents—We classify all highly-liquid instruments with an original maturity of three months or less as cash equivalents. Restricted cash balances at December 31, 2021 and 2020 were $
Inventories— Coal is reported as inventory at the point in time it is extracted from the mine. Coal inventories are valued at the lower of average cost or net realizable value, with cost determined on a first-in, first-out inventory valuation method. Coal inventory costs include labor, supplies, equipment costs, freight, operating overhead, depreciation and amortization. Coal inventory quantities are adjusted periodically based on aerial surveys of coal stockpiles. Supply inventories are valued at average cost and totaled $
Property, Plant and Equipment—Property, plant and equipment is recorded at cost. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in the consolidated statements of operations.
Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.
Mining property and mineral rights costs represent the costs incurred to acquire the rights to access and mine certain coal property either through deeds, leases, or other conveyance agreements. These costs include costs of acquiring, and accessing mineral reserves, resources and surface areas for mining activities.
Capitalized mine development costs represent the costs incurred to prepare mine sites and/or seams of coal for future mining. These costs include costs of acquiring, permitting, planning, research, and developing access to identified mineral reserves and other preparations for commercial production as necessary to develop and permit the properties for mining activities. Operating expenditures including certain professional fees and overhead costs are not capitalized but are expensed as incurred.
The capitalized mine development costs are depleted or amortized on a units-of-production basis as mining of that mine’s assigned reserves takes place. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives ranging from to
39
Advanced Coal Royalties—In most cases, we acquire the right to mine coal reserves under leases which call for the payment of royalties on coal as it is mined and sold. In many cases, these mineral leases require the payment of advance or minimum coal royalties to lessors that are recoupable against future production royalties. These advance payments are deferred and charged to operations as the coal reserves are mined.
Impairment of Long-lived Assets—We review and evaluate long-lived assets, including property, plant and equipment and mine development costs, for impairment when events or changes in circumstances indicate that the asset’s carrying value may not be recoverable. Recoverability is measured by comparing the net book value to the fair value. When the net book value exceeds the fair value, an impairment loss is measured and recorded.
If it is determined that an undeveloped mineral interest cannot be economically converted to proven and probable reserves, or that the recoverability of capitalized mine development costs is uncertain, such capitalized costs are reduced to their net realizable value and an impairment loss is recorded to expense and future development costs are expensed as incurred.
Asset Retirement Obligations—Legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to development costs, at the time they are incurred. Our asset retirement obligations primarily consist of spending estimates related to reclaiming metallurgical coal land and support facilities in accordance with federal and state reclamation laws as defined by each mining permit. We estimate and record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is amortized using the units-of-production method over estimated recoverable reserves upon commencement of mining.
Occupational Disease (Pneumoconiosis) Obligations. We recognize as a liability to provide for occupational disease (pneumoconiosis) benefits to eligible employees, former employees and dependents as required by the Federal Mine Safety and Health Act of 1969, as amended. The occupational disease benefit obligation represents the present value of the actuarially computed present and future liabilities for such benefits over the employees’ applicable years of service using a discount rate.
Estimating the future occupational disease (pneumoconiosis) benefits requires management to make estimates and judgments regarding timing and existence of a liability utilizing third-party actuaries to assist in preparing what constitutes adequate liability amounts. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement awards in the legal and regulatory environments. These estimates are subject to uncertainty due to a variety of factors, including extended lag times in the reporting and resolution of claims, and trends or changes in claim settlement patterns, insurance industry practices and legal interpretations. As a result, actual costs could differ significantly from the estimated amounts. Adjustments to estimated liabilities are recorded in the period in which the change in estimate occurs.
Deferred Income—We accounted for the SBA Paycheck Protection Program Loan (“PPP Loan”) as an in-substance government grant because we expected to meet the PPP Loan eligibility criteria and concluded that the loan represents, in substance, a grant that is expected to be forgiven. Proceeds from the PPP Loan were initially recognized as a deferred income liability. Subsequently, we reduced this liability and recognized income on a systematic basis over the period in which the related costs for which the PPP Loan was intended were incurred. PPP Loan income is presented as other income within the consolidated statements of operations.
Leases—We determine if an arrangement is an operating lease or financing lease at inception. Leases are capitalized on the balance sheet as right-of-use (“ROU”) assets and obligations.
ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating and financing lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of our leases do not provide an implicit rate, we generally use our incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. The operating and
40
financing lease ROU assets also includes any lease payments made and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Financing lease obligations for financing lease payments are reduced over the lease term according to an amortization schedule.
Leases of mineral reserves are exempted under U.S. GAAP from recognition as on the consolidated balance sheets.
Fair Value Measurements— For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring us to make assumptions about pricing by market participants.
Income Taxes—Income tax expense (benefit) includes Federal and state income taxes. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. We account for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet. A valuation allowance is established if it is more likely than not that the related tax benefits will not be realized. In determining the appropriate valuation allowance, we consider the projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and reversals of existing taxable temporary differences.
Uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. We had
Segment Reporting—Our properties located in West Virginia, Virginia and Pennsylvania each consist of mineral reserves for production of metallurgical coal from both underground and surface mines. These operations are within the Appalachia basin. Geology, coal transportation routes to customers, regulatory environments and coal quality or type are characteristic to a basin. For financial reporting purposes, these operations represent a single segment because each possesses similar production methods, distribution methods, and customer quality and consumption characteristics, resulting in similar long-term expected financial performance.
Stock-Based Compensation—We account for employee stock-based compensation using the fair value method. Compensation cost for equity incentive awards is based on the fair value of the equity instrument generally on the date of grant and is recognized over the requisite service period. Forfeitures are recognized as they occur.
The fair value of restricted stock awards is determined using the publicly-traded price of our common stock on the grant date. The fair value of option awards is calculated using the Black-Scholes option-pricing model. The Black-Scholes model requires us to make assumptions and judgments about the variables used in the calculation, including the expected term, expected volatility, risk-free interest rate, dividend rate and service period.
Concentrations—Our operations are all related to metallurgical coal within the mining industry. A reduction in metallurgical coal prices or other disturbances in the metallurgical coal markets could have an adverse effect on our operations. In 2021, 2020 and 2019, approximately
Financial instruments that potentially subject us to a significant concentration of credit risk consist primarily of cash and cash equivalents, restricted cash and accounts receivable. We maintain deposits in federally insured financial
41
institutions in excess of federally insured limits. We monitor the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.
We have a limited number of customers. Contracts with these customers provide for billings principally upon shipment and compliance with payment terms is monitored on an ongoing basis. Outstanding receivables beyond payment terms are promptly investigated and discussed with the specific customer. We estimate an allowance for doubtful accounts based on an analysis of specific customers, taking into consideration the age of past due accounts and an assessment of the customer’s ability to pay. An allowance for doubtful accounts was not necessary as of December 31, 2021 and 2020.
During 2021, sales to
Reclassifications—Financial statements presented for prior periods include reclassifications that were made to conform to the current-year presentation.
Recent Accounting Pronouncements Adopted—In February 2016, the FASB issued ASU 2016-02, Leases, which aims to make leasing activities more transparent and comparable and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. Leases of mineral reserves and related land leases are exempted from the standard. We adopted ASU 2016-02 on January 1, 2019. We elected the “” within the standard which permits us not to reassess prior conclusions about lease identification, lease classification and initial direct costs. We made an accounting policy election to not separate lease and non-lease components for all leases. The adoption of this standard resulted in the recognition of right-of-use assets and lease of $
In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses, which replaces the existing incurred loss impairment model with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We adopted this standard effective January 1, 2020. The adoption of this ASU did not have a material impact on our consolidated financial statements because we do not have a history of credit losses on our financial instruments and have no material expected losses.
In August 2018, the FASB issued ASU 2018-15, Internal-Use Software, which addresses the accounting for implementation costs associated with a hosted service. The standard provides that implementation costs be evaluated for capitalization using the same criteria as that used for internal-use software development costs, with amortization expense being recorded in the same income statement expense line as the hosted service costs and over the expected term of the hosting arrangement. We adopted this standard as of January 1, 2020 on a prospective basis. The adoption of this ASU did not have a material impact on our consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, Income Taxes, which enhances and simplifies various aspects of the income tax accounting guidance, including requirements such as tax basis step-up in goodwill obtained in a transaction that is not a business combination, ownership changes in investments, and interim-period accounting for enacted changes in tax law. The standard was effective for us in the first quarter of 2021. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Recent Accounting Pronouncements Being Assessed—In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments are effective for all entities beginning on March 12, 2020 through December 31, 2022. The Company may elect to apply the
42
amendments prospectively through December 31, 2022. The Company has not adopted this ASU as of December 31, 2021. The Company is currently assessing the impact of adopting this standard on its financial statements and the timing of adoption.
NOTE 3—PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
December 31, | ||||||
(In thousands) |
| 2021 |
| 2020 | ||
Plant and equipment | $ | | $ | | ||
Mining property and mineral rights | | | ||||
Construction in process |
| |
| | ||
Capitalized mine development costs |
| |
| | ||
Less: accumulated depreciation and amortization |
| ( |
| ( | ||
Total property, plant and equipment, net | $ | | $ | | ||
Capitalized amounts related to coal reserves at properties where we are not currently engaged in mining operations totaled $
Depreciation and amortization included:
Year ended December 31, | |||||||||
(In thousands) |
| 2021 |
| 2020 |
| 2019 | |||
Depreciation of plant and equipment | $ | | $ | | $ | | |||
Depreciation of right of use assets | | — | — | ||||||
Amortization of capitalized | |||||||||
mine development costs |
| |
| | | ||||
Total depreciation and amortization | $ | | $ | | $ | | |||
On January 3, 2020, we entered into a mineral lease with the McDonald Land Company for coal reserve tracts which, in many cases, are located immediately adjacent to our Elk Creek complex.
In December 2021, we acquired what are referred to as the “Amonate Assets” from Coronado, pursuant to an asset purchase agreement. The acquisition, for a total cash consideration of $
43
NOTE 4—FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amounts and fair values of our financial assets and liabilities were as follows:
December 31, 2021 | December 31, 2020 | |||||||||||
| Carrying |
| Fair |
| Carrying |
| Fair | |||||
(In thousands) |
| Amount |
| Value |
| Amount |
| Value | ||||
Financial Assets: |
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents | $ | | $ | | $ | | $ | | ||||
Accounts receivable |
| |
| |
| |
| | ||||
Other current assets - restricted cash | | | | | ||||||||
Financial liabilities: | ||||||||||||
Accounts payable |
| ( |
| ( |
| ( |
| ( | ||||
Debt |
| ( |
| ( |
| ( |
| ( | ||||
Senior notes, excluding discounts of $ | ( | ( | — | — | ||||||||
Other current liabilities - financed insurance payable |
| ( |
| ( |
| ( |
| ( | ||||
The estimated fair value of cash, accounts receivable, and accounts payable approximate the carrying amount due to the relatively short maturity of these instruments. The fair value of the Company’s other debt approximates its fair value because the debt has terms that are at prevailing market terms currently available to the Company. We use an observable market data approach to determine the fair value of our Senior Notes, a Level 1 fair-value measurement.
Nonrecurring fair value measurements include asset retirement and occupational disease obligations, the estimated fair value of which is calculated as the present value of estimated cash flows related to its liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, our discount rate, inflation rates and estimated date of expenditures.
NOTE 5—ASSET RETIREMENT OBLIGATIONS
We estimate asset retirement obligations (“ARO”) for final reclamation based upon detailed engineering calculations of the amount and timing of the future cash spending for a third-party to perform the required work. Spending estimates were escalated for inflation at
December 31, | ||||||
(In thousands) |
| 2021 |
| 2020 | ||
Balance at beginning of year | $ | | $ | | ||
Additional asset retirement obligations acquired/incurred |
| |
| — | ||
Expenditures made | ( | ( | ||||
Accretion expense |
| |
| | ||
Revisions to estimates |
| ( |
| | ||
Balance at end of year | $ | | $ | | ||
NOTE 6—WORKERS’ COMPENSATION AND OCCUPATIONAL DISEASE OBLIGATIONS
We are self-insured for certain losses relating to workers’ compensation claims and occupational disease obligations under the Federal Mine Safety and Health Act of 1969, as amended. We purchase insurance coverage to reduce our exposure to significant levels of these claims. Self-insured losses are accrued based upon estimates of the aggregate liability for uninsured claims incurred as of the balance sheet date using current and historical claims experience and certain actuarial assumptions. The occupational disease benefit obligation represents the present value of the actuarially computed present and future liabilities for such benefits over the employees’ applicable years of service using a discount rate of
44
As of December 31, 2021, the estimated aggregate liability for uninsured claims totaled $
NOTE 7—DEBT
Our outstanding debt consisted of the following:
December 31, | ||||||
(In thousands) |
| 2021 |
| 2020 | ||
Term loan | $ | | $ | | ||
Revolving Credit Facility |
| — |
| | ||
Equipment Loans | | | ||||
Senior Notes | | — | ||||
Total debt | $ | | $ | | ||
Current portion of long-term debt |
| |
| | ||
Long-term debt, net | $ | | $ | | ||
Revolving Credit Facility and Term Loan—On November 2, 2018, we entered into a Credit and Security Agreement (as amended or amended and restated) with KeyBank, as the administrative agent, and other lenders party thereto. The Credit Agreement was amended on February 20, 2020 and March 19, 2021. On October 29, 2021, we entered into the Amendment and Restatement with KeyBank. Prior to the Amendment and Restatement, the Credit Agreement consisted of the $
The Revolving Credit Facility has a maturity date of December 31, 2024 and bears interest based on SOFR +
The Term Loan is secured under a Master Security Agreement with a pledge of certain underground and surface mining equipment, bears interest at LIBOR +
The Credit Agreement contains usual and customary covenants including limitations on liens, additional indebtedness, investments, restricted payments, asset sales, mergers, affiliate transactions and other customary limitations, as well as financial covenants. At December 31, 2021, we were in compliance with all financial covenants under the Credit Agreement.
Key Equipment Finance Loan—On April 16, 2020, we entered into an equipment loan with Key Equipment Finance, a division of KeyBank, as lender, in the principal amount of approximately $
9.00% Senior Unsecured Notes due 2026—On July 13, 2021, we completed an offering of $
45
each year, commencing on July 30, 2021. We may redeem the Senior Notes in whole or in part, at our option, at any time on or after July 30, 2023, or upon certain change of control events, at a redemption price equal to
J. H. Fletcher & Co. Loan—On July 23, 2021 and November 24, 2021, we entered into equipment loans with J. H. Fletcher & Co., as lender, in the principal amount of approximately $
Komatsu Financial Limited Partnership Loan—On August 16, 2021, we entered into an equipment loan with Komatsu Financial Limited Partnership, as lender, in the principal amount of approximately $
SBA Paycheck Protection Program Loan— On April 20, 2020, we received proceeds from the PPP Loan in the amount of $
Maturities of our long-term debt are as follows:
(In thousands) | |||
Years ending December 31: |
| ||
2022 | $ | | |
2023 |
| | |
2024 | | ||
2025 | — | ||
2026 | | ||
Total debt before discounts | $ | | |
46
NOTE 8—LEASES
The Company has various financing leases for mining equipment which originated in the second and third quarters of 2021. These leases are generally for terms up to
Right-of-use assets and lease liabilities are determined as the present value of the lease payments, discounted using either the implicit interest rate in the lease or our estimated incremental borrowing rate based on similar terms, payments and the economic environment where the leased asset is located. Below is a summary of our leases:
(In thousands) |
| Classification |
| December 31, 2021 |
| December 31, 2020 | ||
Right-of-use assets | ||||||||
Financing | Financing lease right-of-use assets, net | $ | | $ | — | |||
Operating | | | ||||||
Total right-of-use assets | $ | | $ | | ||||
Current lease liabilities | ||||||||
Financing | Current portion of financing lease obligations | $ | | $ | — | |||
Operating | | | ||||||
Non-current lease liabilities | ||||||||
Financing | Long-term portion of financing lease obligations | $ | | $ | — | |||
Operating | — | | ||||||
Total lease liabilities | $ | | $ | | ||||
Minimum lease payments for our lease obligations are as follows:
December 31, 2021 | |||||||||
(In thousands) |
| Financing |
| Operating |
| Total | |||
Future minimum lease payments: | |||||||||
2022 | $ | | $ | | $ | | |||
2023 | | — | | ||||||
2024 | | — | | ||||||
Total undiscounted lease payments | | | | ||||||
Less: Amounts representing interest | ( | ( | ( | ||||||
Present value of lease obligations | $ | | $ | | $ | | |||
Weighted average remaining term (years) | |||||||||
Weighted average discount rate | |||||||||
As of December 31, 2021, we had financing lease obligations of $
Coal Leases and Associated Royalty Commitments—Leases of mineral reserves and related land leases are exempted under U.S. GAAP from recognition within the financial statements. We lease coal reserves under agreements that require royalties to be paid as the coal is mined and sold. Many of these agreements require minimum annual royalties to be paid regardless of the amount of coal mined and sold. Total royalty expense was $
47
2017 pursuant to the terms of the agreements. Please see Note 12 to the Notes to Consolidated Financial Statements for further discussion related parties.
Future minimum coal lease and royalty payments for each of the next five years and thereafter are as follows:
(In thousands) |
| ||
Years ending December 31: |
| ||
2022 | $ | | |
2023 |
| | |
2024 |
| | |
2025 |
| | |
2026 |
| | |
Thereafter |
| | |
Total minimum payments | $ | |
NOTE 9—EQUITY
We are authorized to issue up to a total of
Stock-Based Compensation—We have a stock-based compensation plan under which stock options, restricted stock, performance-based stock awards and other stock-based awards may be granted. At December 31, 2021,
Options for the purchase of a total of
We grant restricted stock to certain senior executive employees and directors. The shares generally vest over to from the date of grant. During the vesting period, the participants have voting rights and may receive dividends, but the shares may not be sold, assigned, transferred, pledged or otherwise encumbered. Unvested shares are forfeited upon termination of employment, unless an employee enters into another written arrangement. The fair value of the restricted shares on the date of the grant is amortized ratably over the service period. Compensation expense for restricted stock awards totaled $
48
The following table summarizes restricted awards outstanding, as well as activity for the periods:
|
| Weighted | |||
| Average Grant | ||||
Shares |
| Date Fair Value | |||
Outstanding at December 31, 2019 |
| | $ | | |
Granted |
| |
| | |
Vested |
| ( |
| | |
Forfeited |
| ( |
| | |
Outstanding at December 31, 2020 |
| | | ||
Granted |
| |
| | |
Vested |
| ( |
| | |
Forfeited |
| ( |
| | |
Outstanding at December 31, 2021 |
| | $ | | |
The total fair value of awards vested was $
In December 2019, we entered into modification agreements with
NOTE 10—COMMITMENTS AND CONTINGENCIES
Environmental Liabilities—Environmental liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition would coincide with a commitment to a formal plan of action.
Surety Bond—In accordance with state laws, we are required to post reclamation bonds to assure that reclamation work is completed. Reclamation bonds outstanding at December 31, 2021 totaled approximately $
Contingent Transportation Purchase Commitments—We secure the ability to transport coal through rail contracts and export terminals that are sometimes funded through take-or-pay arrangements. As of December 31, 2021, contingent liabilities under these take-or-pay arrangements expiring between December 31, 2022 and March 31, 2024 totaled $
Litigation—From time to time, we are subject to various litigation and other claims in the normal course of business.
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. The trial in the matter commenced on June 29, 2021, in Charleston, West Virginia. On July 15, 2021, the jury returned a verdict in our
49
favor for $
NOTE 11—REVENUE
Our revenue is derived from contracts for the sale of coal which is recognized when the performance obligations under the contracts are satisfied, which is at the point in time control is transferred to our customer. Generally, domestic sales contracts have terms of about
Year ended December 31, | |||||||||
(In thousands) |
| 2021 |
| 2020 |
| 2019 | |||
Coal Sales |
|
|
|
|
| ||||
North American revenues | $ | | $ | | $ | | |||
Export revenues, excluding Canada |
| |
| |
| | |||
Total revenues | $ | | $ | | $ | | |||
As of December 31, 2021, outstanding performance obligations for 2022 totaled approximately
NOTE 12—RELATED PARTY TRANSACTIONS
Mineral Lease and Surface Rights Agreements—Much of the coal reserves and surface rights that we control were acquired through a series of mineral leases and surface rights agreements with Ramaco Coal, LLC. Production royalty payables due to Ramaco Coal, LLC totaling $
On-going Administrative Services—Under a Mutual Services Agreement dated December 22, 2017 but effective as of March 31, 2017, the Company and Ramaco Coal, LLC agreed to share the services of certain of each company’s employees. Each party will pay the other a fee on a quarterly basis for such services calculated as the annual base salary of each employee providing services multiplied by the percentage of time each employee spent providing services for the other party. The services will be provided for 12-month terms, but may be terminated by either party at the end of any 12-month term by providing written notice at least 30 days prior to the end of the then-current term. Charges to Ramaco Coal, LLC were $
50
NOTE 13—INCOME TAXES
Income tax expense (benefit) consisted of the following:
Years ended December 31, | |||||||||
(In thousands) |
| 2021 |
| 2020 |
| 2019 | |||
Current taxes: | |||||||||
Federal | $ | — | $ | — | $ | — | |||
State |
| |
| |
| | |||
Current taxes |
| |
| |
| | |||
Deferred taxes: | |||||||||
Federal |
| |
| ( |
| | |||
State |
| ( |
| ( |
| | |||
Deferred taxes |
| |
| ( |
| | |||
Income tax expense (benefit) | $ | | $ | ( | $ | | |||
The items accounting for differences between income taxes computed at the federal statutory rate and the provision recorded for income taxes were as follows:
Years ended December 31, | |||||||||
(In thousands) |
| 2021 |
| 2020 |
| 2019 | |||
Income taxes computed at the federal statutory rate | $ | | $ | ( | $ | | |||
Effect of: | |||||||||
State taxes, net of federal benefits |
| |
| ( |
| | |||
State tax rate changes, net of federal benefits | ( | — | — | ||||||
Percentage depletion |
| ( |
| ( |
| ( | |||
PPP Loan forgiveness |
| — |
| ( |
| — | |||
Stock-based compensation |
| ( |
| |
| | |||
Other, net |
| |
| |
| ( | |||
Total | $ | | $ | ( | $ | | |||
Deferred tax assets and liabilities were as follows:
December 31, | ||||||
(In thousands) |
| 2021 |
| 2020 | ||
Deferred tax assets: |
|
|
|
| ||
Loss carryforwards U.S. - Federal/States | $ | | $ | | ||
Asset retirement obligations |
| |
| | ||
Accrued expenses |
| |
| | ||
Stock-based compensation |
| |
| | ||
Other |
| — |
| — | ||
Total deferred tax assets |
| |
| | ||
Deferred tax liabilities: | ||||||
Depreciation & amortization |
| ( |
| ( | ||
Net deferred tax liabilities | $ | ( | $ | ( | ||
As of December 31, 2021, our federal net operating loss carryforwards were approximately $
51
NOTE 14—EARNINGS (LOSS) PER SHARE
The following table is a calculation of the net earnings (loss) per basic and diluted share:
Years ended December 31, | |||||||||
(In thousands, except per share amounts) |
| 2021 |
| 2020 |
| 2019 | |||
Numerator |
|
|
|
|
| ||||
Net income (loss) | $ | | $ | ( | $ | | |||
Denominator | |||||||||
Weighted average shares used to compute basic earnings (loss) per share |
| | | | |||||
Dilutive effect of stock option awards |
| | — | — | |||||
Weighted average shares used to compute diluted earnings (loss) per share |
| |
| |
| | |||
Earnings (loss) per share | |||||||||
Basic | $ | | $ | ( | $ | | |||
Diluted | $ | | $ | ( | $ | | |||
Diluted EPS for 2020 and 2019 excludes
NOTE 15—SUBSEQUENT EVENTS
On February 18, 2022, the Company announced that its Board of Directors (“Board”) approved a
On February 23, 2022, Ramaco Development, LLC (“Development”), a wholly owned subsidiary of the Company, entered into a unit purchase agreement (the “Agreement”) with the Company, Ramaco Coal Holdings, LLC (the “Seller”) and Ramaco Coal, LLC (“Target”), pursuant to which Development agreed to purchase
On February 28, 2022 the Company issued the following statement related to the death of Steven H. Hively of Philippi, West Virginia at the Berwind Mine Complex operated by Ramaco Resources, LLC, a subsidiary of the Company. “We were saddened to learn early this morning that a contract employee working underground at our Berwind Mine Complex in McDowell County, West Virginia passed away. We extend our heartfelt thoughts, prayers, and condolences to Mr. Hively’s family, friends and co-workers. Mr. Hively was an experienced miner employed by GMS Mine Repair & Maintenance, Inc. a longtime independent contractor for the Company. The accident was reported immediately to state and federal safety authorities who, along with the company and contractor, are now investigating. The Company is committed to find the cause of this accident.”
52
Regarding the November 5, 2018 Elk Creek raw coal silo failure litigation, on August 12, 2021, the defendants filed a post-trial motion for judgment as a matter of law or in the alternative to alter or amend the judgment or for a new trial. The parties fully briefed the motion and it stood submitted on August 31, 2021. On March 4, 2022, the court entered its memorandum opinion and order on the motion reducing the jury award to a total of $
* * * * *
53
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. Under the supervision and with the participation of our management, including the Chief Executive Officer (“CEO”), the principal executive officer, and Chief Financial Officer (“CFO”), the principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) and 15d - 15(e) promulgated under the Exchange Act, as amended. Based on this evaluation, the Company concluded that our disclosure controls and procedures as of December 31, 2021 specifically relating to information technology systems that support the Company’s financial reporting process were not effective at the reasonable assurance level as a result of the material weakness disclosed below.
Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) of the Exchange Act. Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2021 based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included evaluation of key financial reporting controls, process documentation, accounting policies, and the Company’s overall control environment. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.
As a result of this assessment, management identified a material weakness in internal control over financial reporting related to information technology general controls (ITGCs) in the areas of user access and certain automated and manual business process controls that are dependent on the affected ITGCs. Management has concluded that this deficiency constitutes a material weakness. As a result of the material weakness discussed above, management has concluded that the Company’s internal control over financial reporting was ineffective as of December 31, 2021. Notwithstanding this material weakness, the Company’s management has concluded that the consolidated financial statements, included in the Annual Report, fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting standards.
Management Plans to Remediate Material Weakness. This material weakness did not result in any material misstatement of the Company’s consolidated financial statements for the periods presented. The Company has begun the process of designing and implementing effective internal control measures to improve its internal controls over financial reporting and remediate this material weakness. The Company’s efforts include modifying information technology general controls over user access and implementing additional controls designed to detect issues that may arise over user access and segregation of duties conflicts. We will consider the material weakness remediated after the applicable controls operate for a sufficient period of time, and management has concluded, through testing, that the controls are operating effectively.
Attestation Report of the Registered Public Accounting Firm
Pursuant to Regulation S-K Item 308(b), this Annual Report on Form 10-K does not include an attestation report of our Company’s independent registered public accounting firm regarding internal control over financial reporting.
54
PART IV
Item 15. Exhibits and Financial Statement Schedules
| (a) | The following documents are filed as part of this Annual Report: |
| (1) | Reports of Independent Registered Public Accounting Firms |
Consolidated Balance Sheets as of December 31, 2021 and 2020
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Equity for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements
| (b) | Exhibits |
Exhibit Number |
| Description |
|
| |
2.1 | ||
|
| |
3.1 | ||
|
| |
3.2 | ||
|
| |
3.3 | ||
4.1 | ||
|
| |
4.2 | ||
|
| |
4.3 | ||
|
|
55
Exhibit Number |
| Description |
4.4 | ||
4.5 | ||
4.6 | ||
4.7 | ||
†10.1 | ||
|
| |
10.2 | ||
|
| |
10.3 | ||
|
| |
10.4 | ||
|
| |
10.5 | ||
|
| |
10.6 | ||
| ||
10.7 | ||
|
| |
10.8 | ||
|
| |
10.9 |
56
Exhibit |
| Description |
|
| |
10.10 | ||
|
| |
10.11 | ||
|
| |
10.12 | ||
10.13 | ||
10.14 | ||
|
| |
10.15 |
10.16 | ||
57
Exhibit Number |
| Description |
10.17 | ||
10.18 | ||
10.19 | ||
10.20 | ||
10.21 | ||
|
| |
10.22 | ||
|
| |
10.23 | ||
10.24 | ||
10.25 | ||
10.26 | ||
58
Exhibit Number |
| Description |
10.27 | ||
|
| |
10.28 | ||
|
| |
10.29 | ||
|
| |
10.30 | ||
|
| |
10.31 | ||
|
| |
†10.32 | ||
†10.33 | ||
†10.34 | ||
|
| |
†10.35 | ||
|
| |
†10.36 | ||
|
| |
†10.37 | ||
|
| |
†10.38 | ||
|
|
59
Exhibit Number |
| Description |
†10.39 | ||
|
| |
†10.40 | ||
|
| |
†10.41 | ||
|
| |
†10.42 | ||
|
| |
†10.43 | ||
|
| |
†10.44 | ||
|
| |
†10.45 | ||
†10.46 | ||
†10.47 | ||
†10.48 | ||
†10.49 | ||
†10.50 | ||
†10.51 | ||
†10.52 | ||
†10.53 |
60
Exhibit Number |
| Description |
†10.54 | ||
†10.55 | ||
†10.56 | ||
†10.57 | ||
†10.58 | ||
†10.59 | ||
10.60 | ||
61
Exhibit Number |
| Description |
10.61 | ||
10.62 | ||
10.63 | ||
10.64 | ||
10.65 | ||
†10.66 | ||
10.67 | ||
16.1 | ||
21.1 | ||
*23.1 | ||
*23.2 | ||
23.3 | ||
*23.4 | ||
62
Exhibit Number |
| Description |
*31.1 | Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002 | |
*31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
**32.1 | ||
|
| |
**32.2 | ||
|
| |
95.1 | ||
*96.1 | ||
*96.2 | ||
*101 | Interactive Data Files including the following information from the Annual Report on Form 10-K for the fiscal year ended December 31, 2021, formatted in inline extensible business reporting language (“Inline XBRL”): (i) Cover Page Interactive Data and (ii) the Financial Statements listed on the first page of Item 8. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.” | |
*104 | Cover Page Interactive Data File (formatted in Inline XBRL and included in the Interactive Data Files submitted under Exhibit 101). |
* Exhibit filed herewith.
** Exhibit furnished herewith.
† Management contract or compensatory plan or agreement.
63
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
January 10, 2023 | By: | /s/ Randall W. Atkins |
|
| Randall W. Atkins |
|
| Chairman, Chief Executive Officer and Director |
(Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
January 10, 2023 | By: | /s/ Randall W. Atkins |
|
| Randall W. Atkins |
|
| Chairman, Chief Executive Officer and Director |
|
| (Principal Executive Officer) |
|
|
|
January 10, 2023 | By: | /s/ Jeremy R. Sussman |
|
| Jeremy R. Sussman |
|
| Chief Financial Officer |
(Principal Financial Officer) | ||
January 10, 2023 | By: | /s/ John C. Marcum |
|
| John C. Marcum |
|
| Chief Accounting Officer |
|
| (Principal Accounting Officer) |
|
|
|
January 10, 2023 | By: | /s/ Bryan H. Lawrence |
|
| Bryan H. Lawrence |
|
| Director |
|
|
|
January 10, 2023 | By: | /s/ Richard M. Whiting |
|
| Richard M. Whiting |
|
| Director |
January 10, 2023 | By: | /s/ Patrick C. Graney, III |
|
| Patrick C. Graney, III |
|
| Director |
January 10, 2023 | By: | /s/ C. Lynch Christian III |
|
| C. Lynch Christian III |
Director |
64
January 10, 2023 | By: | /s/ Peter Leidel |
| Peter Leidel | |
Director | ||
January 10, 2023 | By: | /s/ Aurelia Skipwith Giacometto |
|
| Aurelia Skipwith Giacometto |
Director | ||
January 10, 2023 | By: | /s/ David E. K. Frischkorn, Jr. |
|
| David E. K. Frischkorn, Jr. |
Director | ||
January 10, 2023 | By: | /s/ E. Forrest Jones, Jr. |
|
| E. Forrest Jones, Jr. |
Director | ||
65
