PART I

Important Definitions Referenced in this Annual Report

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K are “forward-looking statements” within the meaning of the federal securities laws. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that involve risks and uncertainties that could cause actual results and outcomes to differ materially from results expressed in or implied by our forward-looking statements. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “anticipate,” “believe,” “could,” “continue,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “should,” “will,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

The above list of factors is not exhaustive or necessarily in order of importance. Additional information concerning factors that could cause actual results to differ materially from those in forward-looking statements include those discussed under “Risk Factors” elsewhere in this report. The Company disclaims any intention or obligation to update publicly any forward-looking statements, whether in response to new information, future events, or otherwise, except as required by applicable law.

General

We and our predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. The Company was incorporated in Delaware on June 21, 2017 and became an independent, publicly-traded company on November 28, 2017 when our former parent separated its coal business and natural gas business into two independently traded public companies. As part of the separation, our former parent transferred to the Company substantially all of its coal-related assets, including its Pennsylvania Mining Complex, all of its interest in PA Mining Complex LP (which was then a publicly-traded partnership), the CONSOL Marine Terminal, the Itmann Mine and all of its Greenfield Reserves and Resources located in the Northern Appalachian Basin (“NAPP”), the Central Appalachian Basin (“CAPP”) and the Illinois Basin (“ILB”). On December 30, 2020, we acquired by merger the portion of PA Mining Complex LP that was not originally transferred to us in the separation.

The address of our principal executive offices is 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317. We maintain a website at http://www.consolenergy.com/. The information contained in or connected to the website will not be deemed to be incorporated in this document, and you should not rely on any such information in making an investment decision.

All dollar amounts discussed in this section are in millions of U.S. dollars, except for per unit amounts, and unless otherwise indicated.

Our Company

We are a leading, low-cost producer of high-quality bituminous coal, focused on the extraction and preparation of coal in the Appalachian Basin due to our ability to efficiently produce and deliver large volumes of high-quality coal at competitive prices, the strategic location of our mines and the industry experience of our management team.

Our most significant assets are the PAMC and CONSOL Marine Terminal. Coal from the PAMC is valued because of its high energy content (as measured in Btu per pound), relatively low levels of sulfur and other impurities, and strong thermoplastic properties that enable it to be used in metallurgical, industrial and power generation applications. We take advantage of these desirable quality characteristics and our extensive logistical network, which is directly served by both the Norfolk Southern and CSX railroads, to aggressively market our product to a broad base of strategically selected, top-performing power plant customers in the eastern United States. We also capitalize on the operational synergies afforded by the CONSOL Marine Terminal to export our coal to industrial, power generation and metallurgical end-users globally.

We are also expanding our presence in the metallurgical coal market through the development of our Itmann Mine in West Virginia, which we expect to be fully operational following the relocation and recommissioning of a recently purchased preparation plant, which is planned for completion during the second half of 2022.

Our operations, including the PAMC and the CONSOL Marine Terminal, have consistently generated strong cash flows, even throughout the COVID-19 pandemic. As of December 31, 2021, the PAMC controls 612.1 million tons of high-quality Pittsburgh seam reserves, enough to allow for more than 20 years of full-capacity production. In addition, we own or control approximately 1.4 billion tons of Greenfield Reserves and Resources located in NAPP, CAPP and ILB, which we believe provide future growth and monetization opportunities. Our vision is to maximize cash flow generation through the safe, compliant and efficient operation of this core asset base, while strategically reducing debt, returning capital through share buybacks or dividends, and, when prudent, allocating capital toward compelling growth and diversification opportunities.

Our core businesses consist of our:

A map showing the location of our significant properties is below:

The Company's mission is to improve lives and communities by safely and compliantly producing affordable, reliable energy and profitably growing through innovative technology and perseverance. Our core values of safety, compliance, and continuous improvement are the foundation of the Company’s identity and are the basis for how management defines continued success. We believe the Company’s rich resource base, coupled with these core values, will allow management to create value for the long-term. We believe that the use of coal as a fuel source for electricity use in industrial applications, including but not limited to the steel-making process, will continue for many years. Furthermore, our Itmann project, which is under development, is expected to benefit from the demand related to global infrastructure needs.

Our Strategy

The Company remains focused on increasing stockholder value by safely and compliantly operating our business, developing and growing our metallurgical coal business, and, over time, diversifying into other business opportunities. The Company’s existing coal assets align with these objectives. Our current production from the Bailey, Enlow Fork and Harvey mines can be sold domestically or abroad into the power generation, industrial or metallurgical coal markets. These low-cost mines, with up to five operating longwalls, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals. Our onsite logistics infrastructure at the Central Preparation Plant includes a dual-batch train loadout facility capable of loading up to 9,000 tons of coal per hour and 19.3 miles of track linked to separate Class I rail lines owned by Norfolk Southern and CSX, which significantly increases our efficiency in meeting our customers’ transportation needs. These mines and their logistics infrastructure, along with our 100%-owned CONSOL Marine Terminal, which is served by both Norfolk Southern and CSX, will allow us to continue to participate competitively in the world’s thermal and metallurgical coal markets. The ability to serve both domestic and international markets with premium thermal and crossover metallurgical coal provides tremendous optionality. We have also begun development production from our Itmann Mine project and are starting to explore and invest in some innovative and more sustainable uses for coal. Over the mid- to long-term, the Company is planning to diversify its revenue stream to increase relative contributions from its CONSOL Marine Terminal, metallurgical coal sales and other carbon products, resulting in a reduced exposure to thermal coal.

In order to continue to carry out our strategy, we will continue to adhere to and pursue the following strategic objectives:

Selectively grow our business to maximize stockholder value by capitalizing on synergies with our assets and expertise

We plan to judiciously direct the cash generated by our operations toward those opportunities that present the greatest potential for value creation to our stockholders, particularly those that take advantage of synergies with our asset base and/or with the expertise of our management team. To that end, we plan to regularly and rigorously evaluate opportunities both for organic growth and for acquisitions, joint ventures and other business arrangements in the coal industry and related industries that complement our core operations. The PAMC, the Itmann Mine and our Greenfield Reserves and Resources present the potential for organic growth projects if long-term market conditions are favorable. For example, we are actively engaged in continuous improvement or research and development projects to improve the productivity of our Central Preparation Plant and our mining operations through the use of technology, automation, data visualization and analytics.

We regularly evaluate our Greenfield Reserves and Resources to identify organic growth opportunities that we believe can add value to our business. As such, we announced the commencement of our Itmann Mine project in May 2019 and began development mining in April 2020, which will add a new metallurgical coal product stream to our mix of products upon completion. Our Greenfield Reserves and Resources associated with certain NAPP and CAPP properties provide additional potential organic growth opportunities in the metallurgical coal space, and our Greenfield Reserves and Resources associated with the Mason Dixon and River Mine projects present potential organic growth opportunities in NAPP. Our management team has extensive experience in developing, operating and marketing a wide variety of coal assets, and, we believe, is well qualified to evaluate organic and external growth opportunities. We plan to carefully weigh any capital investment decisions against alternate uses of the cash to help ensure we are delivering the most value to our stockholders.

We are also pursuing a variety of alternative and innovative uses of coal to diversify our business. For example, in December 2019, we acquired a 25% equity stake in CFOAM Corp. (“CFOAM”), which manufactures high-performance carbon foam products from coal that can be used in the industrial, aerospace, military and commercial product markets. The investment in CFOAM represents our first investment in the coal-to-products space. We are also partnering with Ohio University, CFOAM and certain other industry partners on several Department of Energy-funded projects to develop coal plastic composites and carbon foam materials that can be used in engineered composite decking and other building products. Another initiative, our 21^st Century Power Plant project, is also receiving funding from the Department of Energy to evaluate a next-generation power plant at the PAMC that would be fueled by waste coal and biomass and equipped with carbon dioxide (CO₂) capture and storage to achieve net neutral or negative CO₂ emissions. In addition, we have partnered with OMNIS Bailey LLC to develop a refinery that will convert waste coal slurry into a high-quality carbon product that can be used as fuel or as feedstock for other higher-value applications, as well as a mineral matter product that has potential to be used as a soil amendment in agricultural applications. If successfully implemented at full-scale, this project has the potential to add up to 1.5 million tons per year of clean coal production without additional mining of raw tons, as well as to provide a direct benefit by reducing both the volume of and operating costs associated with slurry refuse disposal.

Preserve our share of coal sales to top-performing rail-served power plants in our core market areas, while opportunistically enhancing our industrial and metallurgical presence

We plan to seek to minimize our market risk and maximize realizations by continuing to focus on selling coal to strategically-selected, top-performing, rail-served power plants located in our core market areas in the eastern United States. In 2021, our top domestic power plant customers included ten plants that each took delivery of approximately 500,000 tons or more of PAMC coal. These top power plant customers, which collectively accounted for 88% of our domestic coal shipments in 2021, operated at a 10.2% higher weighted average capacity factor than other NAPP rail-served plants during January through October (the most recent month for which data are available), and none have announced plans to retire during the next five years. We have grown our share of coal supplied at these plants from 11% in 2012 to 37% in the first ten months of 2021, and we believe we can continue to grow this share by displacing less competitive supply from NAPP, CAPP and other basins. We also continue to work on optimizing our portfolio of top customer plants and identifying and penetrating new plants that we believe are aligned with our strategic objectives and would be a good fit for our coal.

Historically, the majority of our production was directed toward our established base of domestic power plant customers, many of which were secured through spot, annual or multi-year contracts. We have continued to diversify our portfolio by placing a growing portion of our production in the export markets, where we sell to industrial and crossover metallurgical end-users. These markets provide us with pricing upside when markets are strong and with volume stability when markets are weak. In 2021, we succeeded in placing 11.0 million tons into the export market and 37% of our total PAMC sales were used in non-power generation applications, up from 8.3 million tons and 18%, respectively, in 2017. Our 2021 export sales of 11.0 million tons represented a record for the PAMC. 

As of February 8, 2022, we are near fully contracted for 2022 and have 11.4 million tons contracted for 2023. We believe our committed and contracted position is well-balanced and provides diversification benefits.

Drive operational excellence through safety, compliance, and continuous improvement

We intend to continue focusing on our core values of safety, compliance and continuous improvement. We operate some of the most productive, lowest-cost underground mines in the coal industry, while simultaneously setting some of the industry’s highest standards for safety and compliance. Over the past five years, our Mine Safety and Health Administration (“MSHA”) total reportable incident rate was approximately 46% lower than the national average underground bituminous coal mine incident rate. Furthermore, our MSHA significant and substantial (“S&S”) citation rate per 100 inspection hours was approximately 68% lower than the industry’s average MSHA S&S citation rate over the twelve-month period ended December 31, 2021. We believe that our focus on safety and compliance promotes greater reliability in our operations, which fosters long-term customer relationships and lower operating costs that support higher margins. Consistent with our core value of continuous improvement, we have improved our productivity at the PAMC from 6.27 tons per employee hour to 8.15 tons per employee hour since 2015, and have reduced our cash costs of coal sold per ton by 18% over this same period. We intend to continue to grow the economic competitiveness of our operations by proactively identifying, pursuing and implementing efficiency improvements and new technologies that can drive down unit costs without compromising safety or compliance.

Maintain Ability to Access Capital Markets

We have generated significant cash from operations since the separation and distribution, which has allowed us to opportunistically refinance and pay down our debt. This reduced indebtedness on our balance sheet and improved liquidity allows us to pursue attractive organic growth opportunities and accretive acquisitions. We constantly seek to improve our capital market capacity to provide additional funds, if needed, to grow our business. We believe that CONSOL Energy can access capital markets to raise debt and equity financing from time to time depending on the market conditions. Furthermore, we successfully accessed the municipal bond market in 2021 and borrowed the proceeds received from the sale of tax-exempt bonds issued by the Pennsylvania Economic Development Financing Authority in an aggregate principal amount of $75 million.

Our Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

Focus on free cash flow generation supported by strong margins and optimized production levels

We intend to continue our focus on maintaining high margins by optimizing production from our high-quality reserves and leveraging our extensive logistics infrastructure and broad market reach. The PAMC’s low-cost structure, high-quality product, favorable access to rail and port infrastructure and diverse base of end-use customers allow it to move large volumes of coal at positive cash margins throughout a variety of market conditions. Through our recent capital investment program, we have improved our mining operations and logistics infrastructure to sustainably drive down our cash operating costs. Furthermore, our ability to enter into multi-year contracts with our longstanding customer base will enhance our ability to generate high margins in varied commodity price environments. We believe that these factors will help enable us to maintain higher margins per ton on average than our competitors and better position us to maintain profitability throughout commodity price cycles.

Extensive, High-Quality Reserve Base

The PAMC has extensive high-quality reserves of bituminous coal. We mine our reserves from the Pittsburgh No. 8 Coal Seam, which is a large contiguous formation of high-Btu coal that is ideal for high-productivity, low-cost longwall operations. As of December 31, 2021, the PAMC included 612.1 million tons of recoverable coal reserves that are sufficient to support more than 20 years of full-capacity production. The advantageous qualities of our coal enable us to compete for demand from a broader range of coal-fired power plants compared to mining operations in basins that typically produce coal with a comparatively lower heat content (ILB and the Powder River Basin (“PRB”)), higher sulfur content (ILB and most areas in NAPP) and higher chlorine content (certain areas of ILB). Our remaining reserves have an average as-received gross heat content of 12,938 Btu/lb, while production from the PRB, ILB, CAPP and the rest of NAPP averages approximately 8,700 Btu/lb, 11,300 Btu/lb, 12,100 Btu/lb and 12,300 Btu/lb, respectively (based on the average quality reported by the United States Energy Information Administration (the “EIA”) for U.S. power plant deliveries for the three years ended June 30, 2021). Moreover, our remaining reserves have an average sulfur content of 2.41%, while production from the ILB averages 2.90% sulfur and production from the rest of NAPP averages 3.34% sulfur (again, based on EIA power plant delivery data for the three years ended June 30, 2021). With our high Btu content and low-cost structure, our 2021 total costs of tons sold averaged $1.40 per mmBtu, which is lower than any monthly average Louisiana Henry Hub natural gas spot price during the past 25 years, and provides a strong foundation for competing against natural gas even after accounting for differences in delivered costs and power plant efficiencies. In addition to the substantial reserve base associated with the PAMC, our Itmann Mine project, which is under development, includes 20.5 million tons of recoverable coal reserves that are sufficient to support more than 20 years of full-capacity production, and our 1.4 billion tons of Greenfield Reserves and Resources in NAPP, CAPP and ILB feature both thermal and metallurgical reserves and resources and provide additional optionality for organic growth or monetization as market conditions allow.

World-Class, Well-Capitalized, Low-Cost Longwall Mining Complex

Based on production per employee, the PAMC is the most productive and efficient coal mining complex in NAPP, averaging 7.71 tons of coal production per employee hour in 2020-2021, compared to 5.30 tons of coal production per employee hour for other currently-operating NAPP longwall mines. For the year ended December 31, 2021, the PAMC produced 8.15 tons of coal per employee hour, compared to an average of 5.70 tons per employee hour for all other currently-operating NAPP longwall mines. We believe our substantial capital investment in the PAMC will enable us to maintain high production volumes, low operating costs and a strong safety and environmental compliance record, which we believe are key to supporting stable financial performance and cash flows throughout business and commodity price cycles.

Strategically Located Mining Operations with Advanced Distribution Capabilities and Excellent Access to Key Logistics Infrastructure

Our logistics infrastructure and proximity to coal-fired power plants in the eastern United States provides us with operational and marketing flexibility, reduces the cost to deliver coal to our core markets and allows us to realize higher free-on-board (“FOB”) mine prices. We believe that we have a significant transportation cost advantage compared to many of our competitors, particularly producers in the ILB and PRB, for deliveries to customers in our core markets and to East Coast ports for international shipping. For example, based on publicly available data and internal estimates, we believe that the transportation cost advantage from our mines compared to ILB mines (not accounting for Btu differences) is approximately $5 to $8 per ton for coal delivered to foreign consumers in Europe and India, up to $3 per ton for coal delivered to domestic customers in the Carolinas, and an even more pronounced cost advantage for coal delivered to domestic customers in the mid-Atlantic states. Our ability to accommodate multiple unit trains from both Norfolk Southern and CSX at the Central Preparation Plant, which includes a dual-batch loadout facility capable of loading up to 9,000 tons of clean coal per hour and 19.3 miles of track with three sidings, allows for the seamless transition of locomotives from empty inbound trains to fully loaded outbound trains at our facility. Furthermore, the PAMC has exceptional access to export infrastructure in the United States. Through our 100%-owned CONSOL Marine Terminal, served by both the Norfolk Southern and CSX railroads, we can participate in the world’s seaborne coal markets with a premium high vol coal product that is well-suited for industrial, power generation and metallurgical applications.

Strong, Well-Established Customer Base Supporting Contractual Volumes

We have a well-established and diverse customer base, comprised primarily of domestic electric-power-producing companies located in the eastern United States. We have had success entering into multi-year coal sales agreements with our customers due to our longstanding relationships, reliability of production and delivery, competitive pricing and high coal quality. More than 87% of our sales in 2021 were to customer companies that were in our 2020 portfolio, and all of our top domestic power plant customers in 2021 (which represent the ten plants to which we shipped approximately 500,000 tons or more of PAMC coal in 2021) have been in our portfolio for at least five consecutive years. In addition, to mitigate our exposure to coal-fired power plant retirements, we have strategically developed our customer base to include power plants that are economically positioned to continue operating for the foreseeable future and that are equipped with state-of-the-art environmental controls. These top plants operated at a 10.2% higher weighted average capacity factor than other NAPP rail-served plants during January through October (the most recent month for which data are available), highlighting their economic competitiveness in the challenging power markets. Moreover, none of our top ten customer plants, which accounted for 88% of our domestic coal shipments in 2021, have announced plans to retire in the next five years. Since 2012, the Company has increased its market share at these ten plants from 11% to 37%.

In addition to our robust domestic customer base, we also have favorable access to seaborne coal markets through our commercial relationships with leading coal trading, brokering and international coal customers. We have grown our exports of PAMC coal to the seaborne markets from 8.3 million tons (or approximately 32% of our annual sales volume) in 2017 to 11.0 million tons (or approximately 47% of our annual sales volume) in 2021.

Highly Experienced Management Team and Operating Team

Our management and operating teams have (i) significant expertise owning, developing and managing complex thermal and metallurgical coal mining operations, (ii) valuable relationships with customers, railroads and other participants across the coal industry, (iii) technical wherewithal and demonstrated success in developing new applications and customers for our coal products in industrial, metallurgical and power generation markets, and (iv) a proven track record of successfully building, enhancing and managing coal assets in a reliable and cost-effective manner throughout all parts of the commodity cycle. We intend to leverage these qualities to continue to successfully develop our coal mining assets while efficiently and flexibly managing our operations to maximize operating cash flow.

CONSOL Energy’s Capital Expenditure Budget

In 2022, CONSOL Energy expects to invest $162 - $195 million in capital expenditures, including spending on the Itmann Mine project. The Company continually evaluates potential acquisitions.

Mining Properties

Information concerning our mining properties in this Annual Report on Form 10-K 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 on Form 10-K, 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 mineral resources can be the basis of an economically viable project. As such, you are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. 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. We have used the term “coal” as in “coal reserves” and “coal resources” interchangeably with “mineral”.

The Company's estimates of recoverable coal reserves and coal resources are estimated internally by competent professionals, including engineers and geologists. These estimates are based on geologic data, coal ownership information and current and/or proposed operating plans. CONSOL’s recoverable coal reserves are proven and probable reserves that could be economically and legally extracted or produced at the time of the reserve determination, considering all material modifying factors. These estimates are periodically updated to reflect past coal production, updated mine plans, new exploration information, and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods or preparation plant processes may increase or decrease the recovery basis for the estimates. The ability to update or modify the estimates of the Company's recoverable coal reserves is restricted to competent geologists and mining engineers and material modifications are documented. The Company's estimates of recoverable coal reserves and coal resources, and supporting information, have been assessed by the John T. Boyd Company, a qualified person firm, which conforms to our requirements under subpart 1300 of Regulation S-K for qualified persons.

The information that follows relating to our individually material properties – PAMC, Itmann Mine, Mason-Dixon Mine, and River Mine – is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRSs”) relating to such properties prepared in compliance with Item 601(b)(96) and subpart 1300 of Regulation S-K by the John T. Boyd Company. 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 TRSs, incorporated herein by reference and made a part of this Annual Report on Form 10-K.

The Company assigns coal reserves to mining complexes, and the amount of coal we assign to each mine is generally sufficient to support mining through the extent of our current mining permits. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured. In addition, our mines and mining complexes may have access to additional reserves that have not yet been assigned.

Some reserves may be accessible by more than one mine because of the proximity of many of our mines to one another. In the following tables, the reserves and resources indicated for a mine are based on our review of current mining plans and reflect our best judgment as to which mine is most likely to utilize the reserve. Recoverable coal reserves and coal resources are either owned or leased. The leases generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, reserves and resources reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.

The following tables provide a summary of all the Company's mineral reserves and mineral resources as determined by the John T. Boyd Company as of the end of the fiscal year ended December 31, 2021:

SUMMARY MINERAL RESERVES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2021

SUMMARY MINERAL RESOURCES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2021

The following table classifies the Company's coal by type (thermal versus metallurgical), region and sulfur content (expressed as lbs. SO₂/MMBtu). The table also classifies metallurgical coal as high, medium and low volatile, which is based on volatile matter content.

CONSOL Energy Recoverable Coal Reserves and Coal Resources

by Product (in Millions of Tons) as of December 31, 2021

Internal Controls Disclosure

The modeling and analysis of the Company's reserves and resources has been developed by Company engineering and geology personnel and reviewed by several levels of internal management. This section summarizes the internal control considerations for the Company’s development of estimations, including assumptions, used in reserve and resource analysis and modeling.

Records from exploration drilling completed on the mining properties comprise the primary data used in the evaluation of the coal resources for each property. The Company maintains written field and exploration guidelines that cover standard procedures ranging from site safety and mapping, including how to: select proper drilling equipment, record accurate and detailed geological logs, perform coal sampling, supervise geophysical logging, and plug drill holes once work was complete.

The Company maintains all control of coal core samples, up to the point that samples are handed over to the lab performing testing. Once logging and sampling is complete, the sampled coal core intervals are transported to the Company’s headquarters by exploration personnel, at which time they are handed over to the quality personnel. The quality personnel arrange pick up by the selected independent lab that will perform the required analyses.  All analytical work was conducted to International Organization for Standardization or ASTM International standards.

Management also assesses risks inherent in coal reserve and resource estimates, such as the accuracy of geophysical data that is used to support mine planning, identify hazards and inform operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess coal reserves and resources or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

Pennsylvania Mining Complex

Pennsylvania Mining Complex. The Pennsylvania Mining Complex is located approximately 26 miles southwest of Pittsburgh, near the city of Washington and the borough of Waynesburg, all in Pennsylvania, and consists of three deep longwall mining operations, the Bailey Mine, the Enlow Fork Mine and the Harvey Mine, and a centralized preparation plant located at approximately 39°58’23.7” N latitude and 80°24’43.6” W longitude. The Company controls approximately 181,068 acres of mineral and/or surface rights as a complex collection of 2,681 owned and/or leased tracts that range from a few acres to several hundred acres in size covered by 1,130 coal deeds and 150 coal lease agreements. Lease terms generally extend until all the coal is removed from the subject tract. Where applicable, royalty rates typically range from 3% to 8% of the gross sales price of the coal. The Company maintains the right to mine and remove almost all of the Pittsburgh Seam within the PAMC boundaries. As part of the PAMC, CONSOL controls surface rights to approximately 16,593 acres through fee simple ownership. This includes ownership of the property upon which the surface facilities for mine access, processing, storing, and shipping are located, as well as 3,509 permitted acres for coarse and fine refuse disposal facilities. Despite a lengthy ownership history dating back to the 1920s with the acquisition of certain coal leases by the Company’s predecessor, commercial operations on the PAMC did not begin until 1984. The total book value of the PAMC and its associated plant and equipment as of December 31, 2021 is approximately $1.5 billion.

The design of the PAMC is optimized to produce large quantities of coal on a cost-efficient basis. The PAMC is able to sustain high production volumes at comparatively low operating costs due to, among other things, its technologically advanced longwall mining systems, logistics infrastructure and safety. All of the PAMC's mines utilize longwall mining, which is a highly automated underground mining technique that produces large volumes of coal at lower costs compared to other underground mining methods. The PAMC typically operates 4-5 longwalls with 15-17 continuous mining sections. The full annual production capacity of the PAMC is up to 28.5 million tons of coal. The central preparation plant is connected via conveyor belts to each of the PAMC's mines and cleans and processes up to 8,200 raw tons of coal per hour. The PAMC's on-site logistics infrastructure at the central preparation plant includes a dual-batch train loadout facility capable of loading up to 9,000 clean tons of coal per hour and 19.3 miles of track linked to separate Class I rail lines owned by Norfolk Southern and CSX, which significantly increases the PAMC's efficiency in meeting its customers' transportation needs. Several regional airports are located near the PAMC and the Pittsburgh International Airport is located approximately 25 miles north of the complex. Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells.

Numerous permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities. Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. As of December 31, 2021, the Company held more than $365 million in surety bonds to cover its obligations relating to mining and reclamation, mine subsidence, stream restoration, water loss, and dam safety with respect to the PAMC.

Bailey Mine. As of December 31, 2021, the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 84.8 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,889 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 4.59. The Bailey Mine is the first mine developed at the Pennsylvania Mining Complex. Construction of the slope and initial air shaft began in 1982. The slope development reached the coal seam at a depth of approximately 600 feet and, following development of the slope bottom, commercial coal production began in 1984. Longwall mining production commenced in 1985, and the second longwall was placed into operation in 1987. In 2010, a new slope and overland belt system was commissioned, which allowed a large percentage of the Bailey Mine to be sealed off. For the years ended December 31, 2021, 2020 and 2019, the Bailey Mine produced 11.8, 8.7 and 12.2 million tons of coal, respectively. 

Enlow Fork Mine. As of December 31, 2021, the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 314.8 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,943 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.35. The Enlow Fork Mine is located directly north of the Bailey Mine. Initial underground development was started from the Bailey Mine while the Enlow Fork slope was being constructed. Once the slope bottom was developed and the slope belt became operational, seals were constructed to separate the two mines. Following development of the slope bottom, commercial coal production began in 1989. Longwall mining production commenced in 1991, and the second longwall came online in 1992. In 2014, a new slope and overland belt system was commissioned and a substantial portion of the Enlow Fork Mine was sealed. For the years ended December 31, 2021, 2020 and 2019, the Enlow Fork Mine produced 6.8, 5.7 and 10.0 million tons of coal, respectively. 

Harvey Mine. As of December 31, 2021, the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 212.5 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,950 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.92. The Harvey Mine is located directly east of the Bailey and Enlow Fork Mines. Similar to the Enlow Fork Mine, the Harvey Mine was developed off of the Bailey Mine’s slope bottom. In order to separate the Harvey Mine from the existing Bailey Mine, seals were built around the original Bailey slope bottom to separate the two mines, and the original slope was dedicated solely to the Harvey Mine. This transfer of infrastructure eliminated the need to make significant capital expenditures to develop, among other things, a new slope, airshaft and portal facility at the Harvey Mine. Development of the Harvey Mine began in 2009, and construction of the supporting surface facilities commenced in 2011. Longwall mining production commenced in March 2014. For the years ended December 31, 2021, 2020 and 2019, the Harvey Mine produced 5.3, 4.4 and 5.0 million tons of coal, respectively. The Harvey Mine’s existing infrastructure, including its bottom development, slope belt and material handling system, has the capacity to add one incremental permanent longwall mining system with additional mine development and capital investment.

The following table sets forth additional information regarding the recoverable coal reserves at the Pennsylvania Mining Complex. 

CONSOL ENERGY PENNSYLVANIA MINING COMPLEX

Recoverable Coal Reserves as of December 31, 2021 and 2020

Itmann Operation

Itmann No. 5 Mine. The Itmann No. 5 Mine is located in Wyoming County, West Virginia, approximately 2.5 miles northwest of the town of Itmann, WV at approximately 37° 35’ 23.65” N latitude and 81° 27’ 14.43” W longitude. The Company controls approximately 20,224 contiguous acres of mining rights (comprising 270 tracts), by ownership or lease, to the Pocahontas 3 seam (P3). The majority (95%) of the acreage is held under coal leases with lengthy terms and are subject to industry standard royalties. The total book value of the Itmann No. 5 Mine and its associated plant and equipment as of December 31, 2021 is approximately $49.9 million .

The first Itmann mine was opened in 1916 by the Pocahontas Fuel Company. In 1956, the Pittsburgh Consolidation Coal Company, the Company’s predecessor, acquired the Pocahontas Fuel Company. During the 1970s, the Itmann mine complex was the Company’s largest operation in CAPP; however, operations were ceased in 1986 due to increasing mining costs and decreasing metallurgical coal prices. In 2019, the Company commenced development of the new Itmann No. 5 Mine, including excavation of the box cut to access the P3 seam.

The mine accesses the P3 seam using a box cut drift entrance near an outcrop along Still Run Hollow. The P3 seam has and continues to be mined extensively within the Appalachian coalfields of southern West Virginia and western Virginia, including the areas immediately surrounding the Itmann No. 5 reserves. As of December 31, 2021, the Itmann Mine's assigned and accessible reserve base contained an aggregate of 20.5 million tons of clean recoverable coal, enough to allow for more than 20 years of full-capacity production. These reserves contain an approximate average quality on a dry basis of 1.00% sulfur, 7.6% ash, and 18.7% volatile matter. Development mining at the Itmann Mine began in 2020. Coal from the Itmann Mine is currently extracted by underground methods using 1-2 continuous miner units, with plans to eventually expand operations to 4-6 continuous miner units to achieve expected capacity of approximately 900 thousand clean tons per year. For the years ended December 31, 2021 and 2020, the Itmann Mine produced 101 thousand and 25 thousand tons of coal, respectively. During 2021, production from the Itmann Mine was sold on a raw basis at the mine to a third-party buyer while the mine and preparation plant were being developed. The Company is currently in the process of relocating and recommissioning a recently purchased preparation plant near the mine site, which is planned for completion during the second half of 2022. General access to the Itmann No. 5 Mine is via a well-developed network of primary and secondary roads serviced by state and local governments. These roads offer direct access to the mine and processing facilities and are generally open year-round. Primary vehicular access to the property is via State Route 10/16, which follows the north bank of the Guyandotte River. The NS railway runs along the south bank of the Guyandotte River. Several regional airports are located within 20 to 30 miles of the Itmann Property. Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells.

As of December 31, 2021, the Company held less than $1 million in surety bonds to cover its current obligations relating to mining and reclamation, mine subsidence, stream restoration, water loss, and dam safety with respect to the Itmann No. 5 Mine. This level of bonding will increase as the mine becomes fully developed and the coal preparation plant facility is constructed and begins operation.

The following table sets forth additional information regarding the recoverable coal reserves at the Itmann Operation. 

CONSOL ENERGY ITMANN OPERATION

Recoverable Coal Reserves as of December 31, 2021 and 2020

Non-Operating Reserves and Resources

Mason Dixon and River Mine

The Company’s Mason Dixon and River Mine properties are greenfield sites located in Greene County, Pennsylvania and Marshall, Monongalia, and Wetzel counties, West Virginia. Geographically, the center of the Mason Dixon and River Mine properties is located at approximately 39°40’02.77” N latitude and 80°34’20.61” W longitude. The properties comprise over 220 square miles within the NAPP coal-producing region of the eastern United States; as such, they are among the largest undeveloped Pittsburgh Seam properties. On December 31, 2021, the Company's estimated potentially underground minable thermal coal resources for Mason Dixon and River Mine were 273.9 million tons and 610.6 million tons, respectively. The total book value of the Mason Dixon and River Mine properties as of December 31, 2021 is approximately $57.4 million.

The Mason Dixon and River Mine Properties comprise over 141,000 acres of coal mineral and/or surface rights. The Company controls approximately 90% (on an active basis) of the mineral rights to the Pittsburgh Seam within the Mason Dixon and River Mine properties. The Company also owns approximately 5,151 surface acres within the property area. These surface rights were acquired for siting various mining, processing, and related facilities. The region is supported by a well-developed network of primary and secondary roads serviced by state and local governments. Roadways that traverse the property’s surface include State Routes 7, 18, 69, 89, and 250. This road network would offer direct access to the property site and is generally open year-round. Several regional airports are located near the properties, with the Pittsburgh International Airport located approximately 70 miles north. Sources of electrical power, water, supplies, and materials are readily available. Electrical power would be provided to the mines and facilities by regional utility companies while water would be supplied by public water services, surface impoundments, or water wells.

The Company holds and maintains four mining permits with the state of West Virginia covering a deep mine, preparation plant, refuse disposal area, and fresh water impoundment for the Mason Dixon property. Four associated National Pollutant Discharge Elimination System permits are also held and maintained for these sites.

Other Properties

The Company also holds other greenfield recoverable coal reserves and coal resources located in NAPP, CAPP and ILB, which are not deemed individually material and had an estimated 533.9 million tons of recoverable coal reserves and coal resources. The Company’s estimate included recoverable high-vol, mid-vol or low-vol metallurgical coal reserves and resources of 91.3 million tons and 121.8 million tons, respectively. Additionally, worldwide demand for metallurgical coal allows some of our recoverable coal reserves and resources, currently classified as thermal coal but that possess certain qualities, to be sold as metallurgical coal. The extent to which we can sell thermal coal as crossover metallurgical coal depends upon a number of factors, including the quality characteristics of the reserve, the specific quality requirements and constraints of the end-use customer and market conditions (which affect whether customers are compelled to substitute lower-quality crossover coal for higher-quality metallurgical coal in their blends to realize economic benefits). 

The following tables set forth our non-operating recoverable coal reserves and coal resources by region. 

CONSOL Energy Non-Operating Recoverable Coal Reserves and Coal Resources

as of December 31, 2021 and 2020

Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained by us at the time we lease or acquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.

The following table sets forth the total royalty tonnage and the amount of income (net of related expenses) we received from royalty payments for the years ended December 31, 2021, 2020 and 2019.

* Excludes advanced mining royalty payments received of $475, $1,198 and $2,289 during the years ended December 31, 2021, 2020 and 2019, respectively.

Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Recoverable reserves do not include reserves attributable to properties that we lease to third parties.

Production

In the year ended December 31, 2021, 99.6% of the Company's production came from underground mines equipped with longwall mining systems (PAMC). The Company employs longwall mining techniques in its underground mines where the geology is favorable and reserves are sufficient. Underground longwall mining uses continuous mining units to develop the mains and gate roads for longwall panels. The longwall systems are highly mechanized, capital intensive operations to efficiently extract coal within the longwall panels. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because the Company has substantial reserves readily suitable to these operations, the Company believes that these longwall mines can increase capacity at a low incremental cost.

The following table shows the production, in millions of tons, for the Company's mines for the years ended December 31, 2021, 2020 and 2019, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquired by us.

*Table may not sum due to rounding.

(1) The Itmann Mine produced 101 thousand tons of coal during the year ended December 31, 2021, and 25 thousand tons of coal during the year ended December 31, 2020.

Coal Marketing and Sales

The following table sets forth the Company produced tons sold and average sales price for the periods indicated:

* The Itmann Mine sold 25 thousand tons of coal during the year ended December 31, 2020.

After a steep decline following the onset of the COVID-19 pandemic in the first half of 2020, demand for our coal improved during the remainder of 2020 and throughout 2021. As a result of this improved global coal demand, continued tightness of coal supply and higher natural gas and electric power prices, we realized higher pricing on both our export contracts and contracts that contain positive electric power-price adjustments, as well as an increase in the volume of coal sold in the year ended December 31, 2021, compared to the year ended December 31, 2020. We sell coal produced by our mines and additional coal that is purchased by us for resale from other producers. Approximately 50% of our 2021 coal sales were made to U.S. electric generators, 46% of our 2021 coal sales were made to export markets and 4% of our 2021 coal sales were made to other domestic customers. Approximately 60% of our 2020 coal sales were made to U.S. electric generators, 38% of our 2020 coal sales were made to export markets and 2% of our 2020 coal sales were made to other domestic customers. Approximately 66% of our 2019 coal sales were made to U.S. electric generators, 33% of our 2019 coal sales were made to export markets and 1% of our 2019 coal sales were made to other domestic customers. We had sales to approximately 35 customers from our 2021 coal operations. During 2021, three customers each comprised over 10% of our total sales, aggregating approximately 40% of our sales. During 2020, three customers each comprised over 10% of our total sales, aggregating approximately 55% of our sales. Annual metallurgical coal revenues for the past three years ranged from $57.5 million to $99.5 million.

Coal Contracts and Pricing

We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. In the ordinary course of business, we make efforts to renew or extend contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past. 

We expect total consolidated Pennsylvania Mining Complex annual sales to be approximately 23-25 million tons for 2022. Domestic coal revenue tends to be derived from contracts that typically have a term of one year or longer and the pricing is typically fixed. Export coal revenue tends to be derived from spot or shorter-term contracts with pricing determined closer to the time of shipment or based on a market index. Some of the Company's contracts span multiple years and have annual pricing modifications, based upon market-driven or inflationary adjustments, where no additional value is exchanged.

The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits. Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of certain force majeure events. Force majeure events include, but are not limited to, unexpected significant geological conditions or natural disasters. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.

Of our 2021 sales tons, approximately 50% were sold to U.S. electric generators, 46% were sold to export markets and 4% were sold to other domestic customers. Of the 46% of our 2021 sales tons sold to export markets, 13% were sold in the metallurgical market and 87% were sold in the industrial and electric power generation markets. In 2021, we derived approximately 40% of our total sales revenue from our top three customers. As of January 1, 2022, we had multiple sales agreements with these customers that expire at various times in 2022 through 2023.

During the past three years, our average realization (sales price per ton sold) for coal produced from the PAMC was $47.17/ton in 2019, $41.31/ton in 2020, and $45.75/ton in 2021. Pricing for our product depends strongly on conditions in the domestic thermal coal market, which accounted for 65% of our total PAMC coal sales in 2020 and 54% in 2021.

The prices we are able to achieve in the domestic thermal market depend on a number of factors, including: (i) the supply-demand balance for Northern Appalachian coal, (ii) prices for other competing sources of energy used for electricity generation, such as natural gas, (iii) power prices in the regions we serve, (iv) prices for coals from other basins (including CAPP, ILB, and PRB) that compete in these same regions, and (v) pricing under our longer-term contracts, which may have been entered into under different market conditions. Lower natural gas prices, coupled with increased capacity from new natural gas combined-cycle power plants and renewable energy sources, put pressure on power prices and on the demand for coal-fired electric power generation. These factors can affect the prices that we are able to achieve in the domestic thermal markets. Similarly, imbalances in global supply and demand for energy fuels can cause substantial variability in pricing in the export markets we serve, which include industrial, metallurgical and power generation applications. Additionally, demand for coal-fired electric power generation experienced a severe decline in 2020 as a result of the COVID-19 pandemic and related government-ordered shutdowns, which resulted in price declines for our coal. Coal prices rebounded significantly in 2021 as economic activity recovered from the 2020 downturn, contributing to higher natural gas and power prices and increased demand for coal-fired electric power generation in the U.S. and abroad, while coal supply remained comparatively constrained, creating more favorable market fundamentals for our product.

Terminal Services

In 2021, approximately 13.8 million tons of coal were shipped through the CONSOL Marine Terminal owned by our subsidiary, CONSOL Marine Terminals LLC. Approximately 82% of the tonnage shipped was produced by the Pennsylvania Mining Complex. The terminal can either store coal or load coal directly into vessels from rail cars. It is also the only major coal terminal located on the east coast of the United States served by two railroads, Norfolk Southern Corporation and CSX Transportation Inc. The CONSOL Marine Terminal has storage capacity of 1.1 million tons with more than thirty acres of capacity for stockpiles. The facility possesses blending capabilities, and it has transloaded approximately 12.7 million tons of coal per year on average over the past five years, with a throughput capacity of approximately 15 million tons annually.

Non-Core Coal Assets and Surface Properties

We own significant coal assets and surface properties that are not in our short or medium-term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our stockholders.

Distribution

Coal is transported from the Company’s mining operations to customers predominantly by railroad cars, vessels or a combination of these means of transportation. Most customers negotiate their own transportation rates, while our sales and logistics specialists negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for the remaining customers.

Seasonality

Our business has historically experienced limited variability in its results due to the effect of seasonal changes. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for our coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to transport coal over our overland conveyor systems and to transport our coal by rail.

Competition

The coal industry is highly competitive, with numerous producers selling into all markets that use coal. There are numerous large and small producers in all coal-producing basins of the United States, and we compete with many of these producers, including those who export coal abroad. Potential changes to international trade agreements, trade concessions and tariffs or other political and economic arrangements may benefit coal producers operating in countries other than the United States. We may be adversely impacted on the basis of price or other factors compared to companies that in the future may benefit from favorable foreign trade policies or other arrangements. In addition, coal is sold internationally in U.S. dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our international competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our international customers’ local currencies, those competitors may be able to offer lower prices for coal to our customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international coal consumers. These coal consumption patterns are influenced by many factors that are beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures, government regulation, technological developments and the location, quality, price and availability of competing sources of fuel.

Indirect competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly older, less efficient coal-fired powered generators. Federal and state mandates for increased use of electricity derived from renewable energy sources could also affect demand for our coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal.

Human Capital Management

As of December 31, 2021, we had 1,575 employees, of which 37 CONSOL Marine Terminal employees were represented by a collective bargaining agreement. We believe our efforts in managing our workforce have been effective, evidenced by a strong culture and a good relationship between the Company and our employees.

Health and Safety. The success of our business is fundamentally connected to the well-being of our people. Accordingly, we are committed to the health, safety and wellness of our employees. We provide our employees and their families with access to health and welfare programs, including benefits that support their physical and mental health by providing tools and resources to help them improve or maintain their health status. In response to the COVID-19 pandemic, we implemented significant operating environment changes that we determined were in the best interest of our employees, as well as the communities in which we operate, and which comply with government regulations and CDC guidelines. This includes, but is not limited to, staggering shift times to limit the number of people in common areas at one time, limiting meetings and meeting sizes, wearing masks, continual cleaning and disinfecting of high-touch and high-traffic areas, including door handles, bathrooms, bath houses, mining equipment, and other areas, limiting contractor access to our properties, limiting business travel, and instituting work from home for administrative employees. We plan to keep these procedures in place and continually evaluate further enhancements for as long as necessary.

Talent. Through our long operating history and experience with technological innovation, we appreciate the importance of retention, growth and development of our employees. Our approach to talent is to both develop talent from within and supplement with external hires. We believe this method has yielded loyalty and commitment in our employee base, which in turn grows our business, while at the same time, adding new employees and external ideas supports a continuous improvement mindset and contributes to our goals of having a diverse and inclusive workforce. We believe that having approximately 48% of the Company's workforce with at least 10 years of company service coupled with our average voluntary retention rate of 93% as of the end of fiscal year 2021 reflects the engagement of our employees.

Total Rewards. As part of our compensation philosophy, we believe that we must offer and maintain market competitive total rewards programs for our employees in order to attract and retain superior talent. In addition to competitive base wages, the Company has additional programs, which include bonus opportunities, a Company-matched 401(k) plan, healthcare and insurance benefits, health savings spending accounts, paid time off, family leave, flexible work schedules, and employee assistance programs.

Laws and Regulations

Overview

Our coal mining operations are subject to various federal, state and local environmental, health and safety regulations. Regulations relating to our operations require us to obtain permits and other licenses; reclaim and restore our properties after mining operations have been completed; store, transport and dispose of materials used or generated by our operations; manage surface subsidence from underground mining; control water and air emissions; protect wetlands and endangered plants and wildlife; and ensure employee health and safety. Furthermore, the electric power generation industry and other users of our coal are subject to extensive regulation regarding the environmental impact of their activities, which could affect demand for our coal.

We seek to conduct our operations in compliance with applicable laws and regulations. However, from time to time, violations occur during operations, and we cannot assure that we have been or will be at all times in compliance with such laws and regulations. Compliance with these laws has substantially increased the cost of coal mining, and the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our coal mining operations or our customers’ ability to use our coal and may require us or our customers to significantly modify operations or incur substantial costs. Additionally, these laws are subject to revision and may become increasingly stringent. The ultimate effect of implementation may not be predictable, as associated regulations may still be in development or subject to public notice, extensive comment or judicial review.

The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we or our customers’ business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations and financial condition.

In recent years, multiple regulations impacting our operations, or our customers' operations, have been subject to revision, repeal and judicial challenge. However, the extent to which these regulations will take effect or survive future presidential administrations is uncertain. In addition, presidential administrations, including the Biden Administration, could, independent of the regulatory process, issue Executive Orders or other Presidential Directives having the force of law that could immediately impact our business or our customers' business. For example, pursuant to the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (“Environment Executive Order”), which was issued on January 20, 2021, President Biden directed the heads of all federal agencies to review “all existing regulations, orders, guidance documents, policies, and any other similar agency actions promulgated, issued, or adopted” during the Trump Administration for consistency with the policies established in the new Biden Administration order. Reversal or reinstatement of earlier regulations, or other presidential executive action, could impact our ability to obtain, maintain or renew permits, could reduce fossil fuels' share of power generating capacity, could expedite the retirements of fossil fuel fired electric generating units, or could reduce the demand for our product in metallurgical and industrial markets, which could have a material adverse effect on our business, financial condition and results of operations.

Environmental Laws

Clean Air Act. The federal Clean Air Act (“CAA”) and corresponding state and local laws and regulations affect all aspects of coal mining operations, both directly and indirectly. The CAA directly impacts our coal mining operations through permitting and emission control requirements for the construction, modification or expansion of certain facilities. Indirectly, the CAA affects the U.S. coal industry by extensively regulating the air emissions of coal-fired electric power generating plants or other industrial facilities operated by our customers.

Coal impurities are released into the air when coal is burned and the CAA regulates specific emissions, such as sulfur, nitrogen oxides, particulate matter, mercury and other substances. In addition, CAA programs such as Maximum Achievable Control Technology (“MACT”) emission limits for Hazardous Air Pollutants, the Regional Haze Program, New Source Review permitting requirements and other federal rulemakings may directly or indirectly affect our operations. Such regulations restricting emissions from coal-fired electric generating plants or other industrial facilities could increase the costs of operating and affect demand for coal as a fuel source, therefore potentially affecting the volume of our sales. Moreover, additional environmental regulations increase the likelihood that existing coal-fired electric generating plants will be decommissioned or replaced with alternative sources of fuel and reduce the likelihood that new coal-fired plants will be built in the future. 

Mercury and Air Toxics Standards Rule. In 2012, the United States Environmental Protection Agency (“EPA”) promulgated or finalized several rules for National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) for new and existing coal-fueled and oil-fueled electric generating plants. The EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) imposed MACT emissions limitations on Hazardous Air Pollutants (“HAPs”), such as mercury, acid gas HAPs, HAP metals and organic HAPs for applicable facilities. The rule was challenged, and ultimately rejected by the U.S. Supreme Court on June 29, 2015, for failing to consider the costs imposed by the MATS Rule. Nevertheless, many coal-fired electric power generators have already taken steps to comply with the MATS Rule, as such required control and operational modifications can take significant time to install and/or implement. On December 27, 2018, the EPA proposed to revise the 2016 supplemental cost finding (“SCF”) for the MATS Rule, as well as the related risk and technology review (“RTR”) required by the CAA. On February 7, 2019, the EPA published a proposed reconsideration, laying the groundwork to rescind the MATS Rule. In the proposed finding, the EPA revised its estimates of the rule's costs and benefits, concluding that it is not “appropriate and necessary” to regulate HAPs from power plants, and sought comment on whether the EPA had authority to rescind the MATS Rule. On April 16, 2020, the EPA completed its reconsideration of the MATS Rule, finalizing its “appropriate and necessary” conclusion while retaining coal- and oil-fired power plants on the list of affected source categories and maintaining existing emission limits for mercury and other HAPs. The final rule became effective on May 22, 2020 and is currently subject to legal challenge in multiple cases before the D.C. Circuit. As directed by the January 2021 Environment Executive Order, on January 31, 2022, the EPA announced its proposed rule revoking the May 2020 SCF and reinstating an April 2016 finding that concluded regulation of HAP emissions from EGUs is appropriate and necessary after considering cost. Separately, the EPA is expected to publish a notice of proposed rulemaking (“NPRM”) suspending, revising, or rescinding the rule's RTR, with a final rulemaking expected in 2023. 

National Ambient Air Quality Standards. The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for six pollutants considered harmful to public health and the environment (“criteria pollutants”) and to review these standards every five years. Areas that are not in compliance with these standards are considered “non-attainment areas.” In recent years, the EPA has adopted more stringent NAAQS, including those for particulate matter (“PM”), nitrogen oxides (“NO_x”), ozone, and sulfur dioxide (“SO₂”). The designation of new non-attainment areas could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans (“SIPs”) that require emission source identification and emission reduction plans. In 2020, the EPA finalized decisions to retain the NAAQS for ozone and PM. Both decisions were subject to legal challenge. Related to the ozone NAAQS, court filings indicate that the EPA plans to issue a proposed rule reconsidering the 70 ppb standard, with a final rulemaking expected in 2023. Consistent with the January 2021 Environment Executive Order, the EPA is currently reconsidering the PM NAAQS, with a NPRM expected in 2022, followed by a final rule in 2023. Further, the Environment Executive Order directed the EPA to establish federal implementation plans (“FIPs”) for ozone compliance in California, Connecticut, New York, Pennsylvania, and Texas by 2022. Final rules may require significant investment in emissions control technologies by our electric power generation or industrial customers, and could affect the demand for our coal.

Cross-State Air Pollution Rule. On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”). CSAPR regulates cross-border emissions of criteria air pollutants such as SO₂, NO_x, fine particulate matter (“PM_2.5”) and ozone in the District of Columbia and 27 states. The CSAPR requires states to limit emissions from sources that “contribute significantly” to noncompliance with air quality standards, such as electric power generating facilities. If the ambient levels of criteria air pollutants are above the thresholds set by the EPA, a region is considered to be in “non-attainment” for that pollutant and the EPA applies more stringent control standards for sources of air emissions located in the region. In October 2016, the EPA finalized revisions to the CSAPR, known as the CSAPR Update Rule. Following litigation in the D.C. Circuit and U.S. Supreme Court, CSAPR was implemented in two phases: Phase 1 began in 2015 and Phase 2 began in 2017. On December 6, 2018, the EPA issued the CSAPR “Close-Out” Rule, a final determination that the CSAPR achieves requirements with respect to the 2008 ground-level ozone NAAQS in 20 states, and accordingly, those states will not be required to impose requirements for further reduction in transported ozone pollution. In addition, the covered states do not need to submit SIPs that would establish additional requirements beyond the existing CSAPR Update. The Close-Out Rule was subject to judicial challenge and was ultimately vacated. On October 30, 2020, the EPA published proposed revisions to the CSAPR Update Rule that would establish new or amend existing Federal Implementation Plans (FIPs) in 12 states to revise emission budgets to reflect additional emissions reductions from EGUs beginning with the 2021 ozone season and also requires power plants in these states to participate in a newly established NO_x emission trading program. The final rule was published on April 30, 2021, and became effective on June 29, 2021. Coal units located in the 12 states were immediately required to use and upgrade previously installed NO_x emissions controls, as applicable. For those facilities that have not yet installed pollution controls for NO_x, the EPA is likely to require additional NO_x reductions in the future. Such requirements could require our customers to incur significant compliance costs and could lead to accelerated plant closures or fuel switching, which could affect the demand for our coal.

Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units (“EGUs”) under CAA Section 111(d). On October 23, 2015, the EPA published a final rule known as the Clean Power Plan (“CPP”), which required states to create systems that reduce carbon dioxide (“CO₂”) emissions from existing coal-fired EGUs by 28% in 2025 and 32% in 2030, compared to 2005 levels under section 111(d) of the CAA. The CPP was subject to numerous legal challenges and was stayed by the U.S. Supreme Court, pending the D.C. Circuit's review of the rule. Before the D.C. Circuit issued its opinion, the Trump administration announced it would reconsider the CPP. In August 2018, the EPA published a proposed rule, the Affordable Clean Energy (“ACE”) rule, that repealed and replaced the CPP.

The final ACE rule was published on July 8, 2019. The ACE rule established greenhouse gas (“GHG”) guidelines for states to use when developing plans to limit CO₂ emissions from coal-fired EGUs. The ACE rule provided that heat rate efficiency improvements are the Best System of Emission Reduction (“BSER”) for coal-fired electric utility sources under the CAA and directed states to develop specific SIPs to implement the rule, and revised CAA section 111(d) regulations to give states greater authority regarding these plans. States could also consider the remaining useful life of the EGUs, as provided by the CAA. Several states and public interest groups petitioned for review of the ACE rule. In addition, several public health petitioners, environmental petitioners and states filed administrative petitions with the EPA seeking reconsideration of the rule. In a March 5, 2021 ruling, the D.C. Circuit issued its partial mandate vacating the ACE rule but leaving the CPP Repeal intact to allow time for the EPA to issue a new rule under section 111(d). The EPA is expected to publish notice of a replacement rulemaking in 2022, with a final rule to follow in 2023. Separately, the Supreme Court agreed to hear four consolidated legal appeals to the D.C. Circuit decision striking down the ACE rule, with a decision expected in mid-2022.

New Source Performance Standards (“NSPS”) for Greenhouse Gas Emissions from New, Modified, or Reconstructed Fossil Fuel-Fired EGUs Under CAA Section 111(b). On October 23, 2015, the EPA published a final rule to limit CO₂ emissions from new, modified and reconstructed fossil fuel-fired EGUs under section 111(b) of the CAA. Pursuant to the rule, newly constructed coal-fired steam EGUs cannot emit more than 1,400 lb CO₂/MWh (gross) and based on a “best system of emission reduction” that was identified as partial carbon capture and storage (CCS). The rule was subject to numerous legal challenges in the D.C. Circuit, which were consolidated under State of North Dakota v. Environmental Protection Agency. The case has been held in abeyance since August 10, 2017, pending the EPA's review of the rule. On December 20, 2018, the EPA published a proposed rule proposing to change its best system of emission reduction determination from partial carbon capture and storage to use of a supercritical boiler, with a change in the emission limits to be 1,900 lb CO₂/MWh (gross) or 2,000 lb CO₂/MWh (gross), depending on the size of the unit. The EPA did not take final action on the 2018 Proposed Rule. On January 7, 2021, the EPA finalized its “Pollutant Specific Significant Contribution Finding (“SCF”) for Greenhouse Gas Emissions from New, Modified and Reconstructed Electric Utility Generating Units” rule, concluding that the EGU source category GHG emissions are significant and warrant regulation. The SCF rule was subsequently challenged in court, and on April 5, 2021, the D.C. Circuit vacated and remanded the rule. The EPA is comprehensively reviewing NSPS for GHG emissions from EGUs, and is expected to release a NPRM in June 2022, followed by a final rule in April 2023.

Global Climate Change

Our customers' consumption of the coal we produce results in the emission of greenhouse gases, particularly CO₂. During operations, our coal mines release methane, a GHG, to promote a safe working environment for our miners underground. GHGs are believed to contribute to warming of the earth’s atmosphere and other climatic changes. As a result, global climate change initiatives and regulations intended to reduce GHG emissions have and are expected to continue to result in (i) the decreased utilization or accelerated closure of existing coal-fired EGUs, (ii) the increased utilization of alternative fuels or generating systems, (iii) a reduction or elimination of new coal-fired power plant construction in certain countries, or (iv) the advancement of technologies aimed toward replacing or minimizing the use of coal in industrial or metallurgical processes.

To date in the U.S., no legislation addressing global climate issues and GHG emissions has been signed into law. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements are uncertain. In the United States, findings published by the EPA in 2009 concluded that GHG emissions pose an endangerment to public health and the environment, and as a result, the EPA has the authority to adopt and implement regulations restricting GHG emissions under existing provisions of the CAA. 

In addition, the U.S. Global Climate Change Research Program, a consortium of governmental departments and agencies, issued the Fourth National Climate Assessment (“NCA”) on November 23, 2018. The NCA is a congressionally mandated report, to be completed every four years as mandated under the Global Change Research Act of 1990. The report summarizes observed effects of increasing GHG concentrations on the U.S. weather and climate, while proposing certain measures to reduce climate-related risks. Separately, the U.S. House Select Committee on the Climate Crisis released its report, known as The Climate Crisis Action Plan, in June 2020, followed by the Senate Democrats' Special Committee on the Climate Crisis's report, “The Case for Climate Action”, in August 2020. Both reports call for the U.S. to achieve net-zero emissions no later than 2050. While no regulatory actions have been issued as a result of the NCA or legislative committee reports, they could be relied upon to justify policy or executive action in the future.

For example, since assuming office, President Biden has signed multiple Executive Orders (EO) aimed at utilizing a whole of government approach to address climate change. EO 14008: Tackling the Climate Crisis at Home and Abroad, signed on January 27, 2021, includes provisions supporting an end to international financing of fossil fuel-based energy and seeks a reduction in climate pollution from every sector of the economy. EO 14057: Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, signed on December 8, 2021, emphasizes federal actions to support a carbon pollution free electricity sector by 2035 and seeks to achieve net zero emissions economy wide no later than 2050. Regulations, policies and uncertainty regarding the future course of these actions could immediately impact our business or our customers' businesses and could eventually reduce the overall demand for our coal.

Since 2011, the EPA has required active underground coal mines and certain support facilities exceeding a minimum GHG emission threshold to report annual emissions to the EPA under the Mandatory GHG Reporting Rule, which is expected to be revised in 2022. These emissions are not currently regulated by the EPA. Previous petitions and judicial challenges seeking to compel the EPA to classify coal mines as stationary sources appropriate for regulation have been unsuccessful to date. If the EPA were to regulate coal mine methane emissions in the future, we would likely be required to install additional pollution control devices, pay fees or taxes for our emissions, or incur expenses associated with the purchase of emissions credits, in order to continue operation. Alternatively, we may need to curtail coal production. The magnitude of impact on our operations, capital expenditures, financial condition or cash flows would be dependent on the structure of any proposed regulation and the degree of emission reduction prescribed.

In the absence of sweeping federal legislation on GHG emissions in the United States, a number of states, governors, mayors and businesses have committed to broad goals for GHG reductions or requirements to deploy carbon-free or renewable sources of electricity. Such goals include those announced by multiple domestic utilities, including some of our customers, pledging to substantially reduce or to achieve net zero GHG emissions, to accelerate closure of existing coal-fired power generating stations, or to increase generating capacity from natural gas or renewable sources. These goals could ultimately affect the demand and prices for our coal, as these customers seek to achieve such voluntary goals over time. At the state level, on October 3, 2019, Pennsylvania Governor Tom Wolf issued an Executive Order, “Commonwealth Leadership in Addressing Climate Change through Electric Sector Emissions Reductions,” directing the state’s Department of Environmental Protection to begin a rulemaking process that will allow Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”), and Virginia recently began complying with RGGI in 2021. RGGI is a mandatory cap-and-trade program among 11 northeastern states to reduce CO₂ emissions from the power sector. Similar to other mandatory cap-and-trade initiatives, such as California's cap-and-trade program, RGGI seeks to limit CO₂ emissions annually, in order to achieve a prescribed long-term emissions reduction target. In cap-and-trade scenarios, power generators or other GHG emitters are required to purchase allowances, available through auction or a secondary market, that are equal to one ton of CO₂ emissions, thereby increasing the cost of electric power generation. 

In response to the Governor's Order, the Pennsylvania Environmental Quality Board (PAEQB) published a proposed rulemaking to establish the Commonwealth's participation in RGGI and to institute a CO₂ budget trading program limiting emissions from fossil fuel-fired EGUs with a minimum nameplate capacity of 25 megawatts (MWe) on November 7, 2020. In 2021, the PAEQB and the PA Independent Regulatory Review Commission (IRRC) subsequently voted to adopt the regulation. Additionally, the PA Attorney General's Office determined that RGGI participation does not conflict with state law, based on its limited review under the Commonwealth Attorneys Act. Prior to the RGGI rule's approval, in 2020, the PA General Assembly introduced and passed House Bill (“HB”) 2025 requiring legislative approval from both chambers of the General Assembly for any action imposing a revenue-generating tax or fee intended to reduce CO₂ emissions, but HB 2025 was subsequently vetoed by Governor Wolf. After the PA IRRC voted to adopt the RGGI rule, the PA Senate and House passed Senate Concurrent Regulatory Review Resolution 1 (SCRRR 1) disapproving of the regulation on October 27 and December 15, 2021, respectively. However, the resolution was subsequently vetoed by Governor Wolf. Absent an override, the RGGI rule is expected to be finalized in 2022 but will likely be subject to legal challenges that could delay its implementation. If enacted, the proposed Pennsylvania CO₂ Budget Trading Program regulation could result in decreased demand or decreased prices for our domestic coal in the state of Pennsylvania. Similarly, in 2021, North Carolina Governor Ray Cooper signed House Bill 951 into law, codifying the state's primary climate change plan. The bill endeavors to reduce CO₂ emissions by 70% by 2030, compared to 2005 baseline levels and to achieve carbon neutrality by 2050. The bill is expected to speed the retirement of coal-fired units in the state, and could result in decreased demand or decreased prices for our coal. Further, CO₂ cap and trade programs, carbon taxes, or other regulatory and policy regimes, whether state, federal or international in nature, or related business or customer focused voluntary climate and GHG emission reduction goals could affect the future market for coal and lower overall coal demand.

At both the state and federal levels, environmental organizations, third parties and regulators have challenged permitting actions associated with new fossil fuel infrastructure, power plants and pipelines, citing GHG emissions, the uncertainty surrounding the economic viability of these projects under future laws limiting CO₂ emissions, or the failure to account for the climate change impacts. Challenges such as these could result in litigation and delays to permit approval, which could reduce production, cash flow and results of operations.

Foreign governments, including the European Union and member countries, have adopted regulations governing GHG emissions. Independent of regulation, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (UNFCCC) became effective in 2005 and established a binding GHG emission reduction requirement for developed countries. The Kyoto Protocol has never been ratified by the U.S. Senate. Similarly, in December 2015, the U.S. and approximately 200 nations signed the international Paris Agreement, making voluntary commitments to limit or reduce GHG emissions in order to limit global warming below 2 degrees Celsius from temperatures in the pre-industrial era by 2100. On June 1, 2017, the Trump Administration announced the United States' withdrawal from the agreement, which became effective on November 4, 2020. On January 20, 2021, President Biden signed an Executive Order rejoining the U.S. into the Paris Accord. The UNFCCC convened its 26th Conference of the Parties (COP26) in November 2021, and ultimately enacted the Glasgow Climate Pact to operationalize Article 6 of the Paris Agreement. Article 6 establishes a framework for the voluntary international cooperation of countries to reduce GHG emissions and meet nationally determined contributions (NDCs). The Pact also calls on governments to accelerate the dissemination of technologies, and the adoption of policies, to transition toward a low-emission energy system, including by accelerating the phasedown of unabated coal power and phase-out of fossil fuel subsidies. As a result, nations could come forward with revised NDCs in 2022, including 2030 targets aligned with the Paris Agreement's temperature goals.

Federal, state and international GHG and climate change initiatives, associated regulations or other voluntary commitments to reduce GHG emissions could significantly increase the cost of coal production and consumption, increase costs as a result of regulations requiring the installation of emissions control technologies, increase expenses associated with the purchase of emissions reduction credits to comply with future emissions trading programs, increase expenses associated with any future carbon tax, or significantly reduce coal consumption through implementation of a future clean energy standard. Such initiatives and regulations could further reduce demand or prices for our coal in both domestic and international markets, could adversely affect our ability to produce coal and to develop our reserves, could reduce the value of our coal and coal reserves, and may have a material adverse effect on our business, financial condition and results of operations.

Clean Water Act

The federal Clean Water Act (“CWA”) and corresponding state laws affect our coal operations by regulating discharges into certain waters. CWA permits - issued either by the EPA or an analogous state agency - typically require regular monitoring and compliance with limitations on defined pollutants and reporting requirements. Specific to the Company's operations, CWA permits and corresponding state laws at times require (i) treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, sulfates, selenium and dissolved solids and (ii) requirements to dispose of wastes at approved disposal facilities.

Under the CWA, citizens may sue permit holders for alleged discharges of pollutants not explicitly limited by NPDES permits or citizens may sue to enforce NPDES permit requirements. Beginning in 2012, multiple citizen suits have been filed, alleging violations of numeric and narrative water quality standards that broadly prohibit effects to aquatic life. The suits seek penalties and injunctive relief that could limit future discharges or impose expensive treatment technologies. While the outcome of these suits cannot be predicted, court rulings could result in additional treatment expenses that could affect our operations. Additional CWA requirements that could directly or indirectly affect our operations are summarized below.

Dredge and Fill Permits Under CWA Sections 401 and 404. In order to obtain a permit for certain coal mining activities, such as the construction of coal refuse areas and slurry impoundments that may result in impacts to waters of the United States, an operator may need to obtain a permit for the discharge of fill material from the Army Corps of Engineers (“ACOE”) under Section 404 of the CWA. Alternatively, for specific categories of activities determined to have minimal effects, the Company may be required to obtain Nationwide Permits from the ACOE. Subject to minimum thresholds, all permits associated with the placement of dredge or fill material require appropriate mitigation. Through the CWA Section 401 Certification Program, state regulators have approval authority over federal permits authorizing discharges in state waters or impacts to aquatic resources and must certify that the activity will comply with water quality standards or other applicable requirements. In 2020, the EPA issued the 2020 CWA Section 401 Certification Rule, intending to clarify the scope of state regulatory authority and under certain circumstances, allowing the EPA to certify projects regardless of state objection. The rule was vacated by the U.S. District Court for the Northern District of California on October 21, 2021. The Court ordered a temporary return to the EPA's 1971 section 401 certification rule until the EPA finalizes a new rule. As a result of the requirement to receive explicit authorization from the ACOE and the corresponding state regulatory authority before proceeding with mining activities, our operations could experience permitting approval timeframe delays.

Definition of Waters of the United States. In June 2015, the EPA issued a rule to clarify which waterways are subject to federal jurisdiction under the CWA, known as the Clean Water Rule. The rule was ultimately blocked by a federal appeals court and in 2019, the EPA and the ACOE promulgated a final rule (i) repealing the 2015 definition of “Waters of the United States” (“WOTUS”) and (ii) redefining which waterbodies are subject to federal jurisdiction. On April 21, 2020, the EPA and ACOE published the Navigable Waters Protection Rule (“NWPR”), revising the previously codified definition of WOTUS. The NWPR became effective on June 22, 2020 in multiple courts. However, in 2021, the NWPR was vacated by the U.S. District Court for the District of Arizona and separately vacated and remanded by the U.S. District Court for the District of New Mexico. As a result of these decisions and consistent with the Environment Executive Order, the EPA announced its intent to re-evaluate the definition of WOTUS in two phases. In December 2021, the EPA and the ACOE published a proposed rule, restoring the regulations in place prior to the 2015 Clean Water Rule but updating those regulations to be consistent with relevant Supreme Court decisions. By increasing the number of waterbodies subject to CWA permitting and other regulations, revisions to the definition of WOTUS could impose additional permitting obligations or restrictions, required enhanced mitigation, or cause the Company to modify its operations which could result in delayed permit approval timeframes or increased costs.

Water Discharge Permits. Additionally, the Company must obtain National Pollution Discharge Elimination System (“NPDES”) permits from the appropriate state or federal permitting authority under Section 402 of the CWA. These permits establish effluent limitations for discharges to receiving waters that are protective of water quality standards. For discharges to receiving waters that are classified as either high-quality or impaired, stringent restrictions are established to ensure anti-degradation and compliance with water quality standards. Permitting such discharges under NPDES could increase the cost, time and difficulty of complying with permit requirements, and may warrant costly treatment that could affect our operations.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. The 2015 Effluent Limitations Guidelines and Standards (“ELG”) rule revised the regulations for the Steam Electric Power Generating category. The rule established the first federal limits on the levels of toxic metals in various power plant wastewater discharges, and set zero discharge requirements for certain waste streams. The rule was subject to legal challenge, with the Fifth Circuit of Appeals ultimately vacating portions of the rule regulating legacy wastewater and residual combustion leachate in 2019. The 2015 final ELG rule was published on October 13, 2020 and established a voluntary incentive program which provides power plants until December 31, 2028 to (i) retire or (ii) implement changes required to achieve compliance with stringent effluent limits and standards. The rule is expected to significantly increase compliance costs for many coal-fired power plants and as a result, could accelerate closure. Certain domestic utilities, including some of our current customers, have announced plans to retire by 2028 as a result of the ELG rule. In accordance with the Environment Executive Order, on August 3, 2021, the EPA announced its decision to implement the 2020 ELG Reconsideration Rule and to simultaneously conduct a rulemaking that could strengthen ELGs for waste streams addressed, as well as waste streams excluded, in the 2020 final rule. The draft ELG reconsideration rule, which will also address claims in current litigation pending in the Fourth Circuit Court of Appeals, is expected to be published in 2022.

Other Environmental Laws and Regulations

Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum extraction, environmental, reclamation, and closure standards for mining activities. While SMCRA is a comprehensive statute, it does not supersede other major statutes such as the Clean Air Act, Clean Water Act, Endangered Species Act and other statutes discussed herein. Operators must obtain SMCRA permits and permit renewals from the U.S. Office of Surface Mining (“OSM”) or from the applicable state agency, where states have been granted regulatory primacy by demonstrating that the state’s regulatory program is at least as stringent as the federal program. Our active operations are located in states which have achieved primary jurisdiction for enforcement of SMCRA, with oversight from OSM. The timing of SMCRA permit issuance is largely at the discretion of the regulatory authorities and is often related to the size and complexity of the operation seeking approval. In addition, numerous other permits from applicable state, federal or local authorities are required to conduct mining operations. Timing of permit issuance can also be influenced by public engagement in the permitting process, such as through comment, hearings, or legal interventions which could affect our operations. Permits can also be delayed, refused, or revoked if any entity under common ownership or control has unabated permit violations, including the mining and compliance history of officers, directors, and principal owners of the entity seeking permit approval. Under the laws applicable to our operations, substantial fines and penalties, including suspension or revocation of permits, and in severe cases, criminal sanctions, may be imposed for failure to comply.

Under federal and state laws, including SMCRA, we are required to obtain surety bonds or other acceptable security to secure payment of our long-term obligations, including mine closure and reclamation, mine water treatment, federal and state workers’ compensation costs, coal leases, or other miscellaneous obligations. Surety bonds are typically renewable on a yearly basis and it is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral therefor. In recent years, surety bond costs have increased, the market terms of surety bonds have generally become less favorable, including increases in the amount of collateral required to secure surety bonds, and the number of companies willing to issue surety bonds has decreased. Any failure to maintain, or our inability to acquire, surety bonds required by state and federal laws or the related collateral required by bond issuers, could have a material adverse effect on our ability to produce coal, adversely affecting our business, financial condition, liquidity, results of operations and cash flows. As of December 31, 2021, we posted an aggregated $537 million in surety bonds for reclamation purposes, as well as approximately $277 million in surety bonds, cash, and letters of credit to secure other obligations including workers compensation, coal lease and other obligations.

In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund, which is used to restore mine lands mined, closed or abandoned before SMCRA’s adoption in 1977, and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee of $0.12 per ton for underground mined coal expired on September 30, 2021. The current fee, effective on October 1, 2021, is $0.096 per ton for underground mined coal. We recognized expense related to Abandoned Mine Reclamation Fund fees of $3 million for the year ended December 31, 2021.

Endangered Species Act. The federal Endangered Species Act (“ESA”) and other related federal and state statutes protect species that have been classified as endangered or threatened with possible extinction, or other protective designations. Protection of these species could prohibit or delay authorization of mining activities or may place additional restrictions on our operations related to timbering, construction, vegetation, or water discharges. A number of species indigenous to our operating areas are protected under the ESA or other related laws and regulations. Rules that were intended to update the ESA as it relates to: (i) factors for the listing, delisting, or reclassifying of species, and the designation of critical habitat, and (ii) the blanket extension of prohibitions for endangered species to threatened species became effective in 2019, and were subject to challenge from several states and environmental groups. Additional rules regarding noncritical habitat were promulgated in December 2020 and were also subject to judicial challenge. On October 27, 2021, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service proposed separate rules to rescind and revise the ESA critical habitat regulations and definitions finalized under the previous administration, with final rules expected to be promulgated in 2022. If more stringent or protective measures were required, or if additional critical habitat areas were designated, our operations could be exposed to additional requirements, increased operating costs or delayed approval timeframes.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to taking a “major Federal action”, which encompasses agencies' decisions on certain permitting applications that fall under federal jurisdiction. NEPA reviews require federal agencies to review the environmental impacts of their decisions, including those associated with GHG emissions and the effects of climate change. Agencies must issue either an Environmental Impact Statement (“EIS”) or an Environmental Assessment (“EA”), which may create delays in project review and authorization timeframes or increase the cost of compliance. In July 2020, the White House Council on Environmental Quality (“CEQ”) promulgated the NEPA Update Rule, seeking to streamline the NEPA process and minimize unnecessary litigation, cost, and delay for project proponents; however, the rule was subject to legal challenge. Separately, in 2020, the CEQ published a “Draft NEPA Guidance on Consideration of Greenhouse Gas Emissions” to replace guidance previously issued in 2016. The Draft guidance seeks to clarify the scope of review federal agencies should undertake when considering the effects of GHG emissions under NEPA, and was never published in final form. Certain Federal courts have held that GHGs must be considered under NEPA prior to a federal agency taking a “major Federal action”. As directed by the Environment Executive Order, the CEQ rescinded the 2019 Draft GHG Guidance in February 2021 and is separately expected to publish revisions to the NEPA rule in two phases in 2022.

Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) imposes remediation requirements related to actual or threatened releases of hazardous substances into the environment. Under CERCLA or related state laws, joint and several liability may be imposed on generators of hazardous waste, site owners, waste transporters or others regardless of fault associated with the original disposal activity. Although the EPA excludes most wastes generated during coal mining and processing from hazardous waste laws, such wastes may contain hazardous substances that are governed by CERCLA if released to the environment. Our current operations, operations of our predecessors, or facilities to which we have sent waste materials could be subject to liability under CERCLA.

Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations affect coal mining by imposing requirements for the treatment, storage, transportation and disposal of certain wastes created throughout the coal mining process. Facilities where certain regulated wastes have been treated, stored or disposed of are subject to RCRA and may receive corrective action orders for instances of non-compliance or release of a hazardous substance to the environment. Many waste streams created throughout the mining process are excluded from the regulatory definition of hazardous waste, and coal operations authorized under SMCRA are exempt from RCRA permitting requirements. Byproducts of coal combustion, or coal combustion residuals (“CCR”), are also regulated under RCRA. In April 2015, the EPA published regulations for the disposal of CCR from electric utilities and independent power producers (the “CCR Rule”). Importantly, CCR are regulated under RCRA as “non-hazardous” waste and avoid the stricter, costlier regulations under RCRA's “hazardous” waste rules. The CCR Rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances. Certain provisions of the revised CCR Rule were vacated by the D.C. Circuit in 2018. The EPA is expected to finalize additional rules addressing those specific provisions in 2022 and 2023. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCR facilities who sought approval to continue disposal of CCR and non-CCR waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA is requiring the remaining 8 facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022. The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. Further, the Water Infrastructure Improvements for the Nation (“WIIN”) Act authorized the EPA to establish a federal permitting program for states and territories that do not have an approved permitting program for the disposal of CCR in surface impoundments and landfills under RCRA. Accordingly, the EPA published a proposed rule establishing a federal program on February 20, 2020. A final rule is expected in 2022. The CCR rules impose new requirements that would generally increase the cost of CCR management or require facility closure. The combined effect of the CCR rules and ELG regulations (discussed above) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

Other Environmental Regulations. We are required to comply with other state, federal and local environmental laws in addition to those discussed above. These laws include, for example, the Safe Drinking Water Act, the Emergency Planning and Community Right to Know Act, the Toxic Release Inventory, and the rules governing the use and storage of explosives regulated by the U.S. Bureau of Alcohol, Tobacco, and Firearms and the Department of Homeland Security.

Health and Safety Laws

Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined-out areas, and engage in additional training. We have also experienced more aggressive inspection protocols and with new regulations, the volume of civil penalties has increased. Recent actions taken by federal and state governments include requiring:

On September 2, 2015, MSHA published proposed rules for underground coal mining operations concerning proximity detection systems for coal hauling machines and scoops. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. MSHA has not issued a final rule regarding these proposed rules.

On January 15, 2015, MSHA published a final rule requiring underground coal mine operations to equip continuous mining machines (except full-face continuous mining machines) with proximity detection systems. The proximity detection system strengthens protection for miners by reducing the potential of pinning, crushing and striking hazards that result in life-threatening injuries and death. The final rule became effective March 15, 2015 and included a phased in schedule for newly manufactured and in-service equipment.

In 2010, MSHA rolled out the “End Black Lung, Act Now” initiative. As a result, MSHA implemented a new final rule on August 1, 2014 to lower miners’ exposure to respirable coal mine dust including using the new Personal Dust Monitor technology. This final rule was implemented in three phases. The first phase began on August 1, 2014 and utilized the current gravimetric sampling device to take full shift dust samples from the current designated occupations and areas. It also required additional record keeping and immediate corrective action in the event of overexposure. The second phase began on February 1, 2016 and required additional sampling for designated and other occupations using the new continuous personal dust monitor (“CPDM”) technology, which provides real time dust exposure information to the miner. CPDM equipment was purchased and was placed into service which was required to meet compliance with the new rule. Dust Coordinators and Dust Technicians were hired in order to meet the staffing demand to manage compliance with the new rule. The final phase of the rule went into effect on August 1, 2016. The current respirable dust standard was reduced from 2.0 to 1.5mg/m3 for designated occupations and from 1.0 to 0.5mg/m3 for Part 90 Miners (coal miners who show evidence of the development of black lung disease).

Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to: