CONSOL Energy Inc. - Annual Report: 2020 (Form 10-K)

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 CONSOL Coal Resources LP, the CONSOL Marine Terminal, the Itmann Mine and all of its Greenfield Reserves 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 CONSOL Coal Resources 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.

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 as well as thermal 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 thermal and metallurgical end users globally.

Our operations, including the PAMC and the CONSOL Marine Terminal, have consistently generated positive cash flows, even through the 2020 COVID-19 pandemic. As of December 31, 2020, the PAMC controls 657.9 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 1.5 billion tons of Greenfield Reserves 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, allows management to create value for the long-term. We believe that the use of coal as a fuel source for electricity in the United States 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.

Merger with CONSOL Coal Resources LP

On December 30, 2020, we completed the acquisition of all of the outstanding common units of CONSOL Coal Resources, and CONSOL Coal Resources became our indirect wholly-owned subsidiary (see Note 2 - Major Transactions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). In connection with the closing of the CCR Merger, we issued approximately 8.0 million shares of our common stock to acquire the approximately 10.9 million common units of CCR held by third-party CCR investors at a fixed exchange ratio of 0.73 shares of CEIX common stock for each CCR unit, for total implied consideration of $51.7 million.

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, as either thermal coal or high volatile metallurgical coal. These low-cost mines, with five 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 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 shareholder 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 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 and automation, such as de-bottlenecking projects at the Central Preparation Plant, shearer automation technology and data visualization and analytics.

We regularly evaluate our Greenfield Reserves 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 associated with the Martinka Mine and Birch Mine provide additional potential organic growth opportunities in the metallurgical coal space, and our Greenfield Reserves 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 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 shareholders.

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. Our Coal FIRST 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.

Continue to grow our share of coal sales to top-performing rail-served power plants in our core market areas, while opportunistically pursuing export and crossover metallurgical opportunities

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 2020, our top domestic power plant customers included ten plants that each took delivery of approximately 400,000 tons or more of PAMC coal. These top power plant customers, which collectively accounted for 74% of our domestic coal shipments in 2020, operated at a 13.2% 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 27% in the first ten months of 2020, 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.

While the majority of our production is directed toward our established base of domestic power plant customers, many of which are secured through annual or multi-year contracts, we also have continued to diversify our portfolio by placing a growing portion of our production in the export markets. These markets provide us with pricing upside when markets are strong and with volume stability when markets are weak. As of February 9, 2021, our contracted position is 18.2 million and 5.6 million tons for 2021 and 2022, respectively. 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 42% 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 63% lower than the industry’s average MSHA S&S citation rate over the twelve-month period ended December 31, 2020. 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 7.21 tons per employee hour since 2015, and have reduced our cash costs of coal sold per ton by 16% 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 free cash flow 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 allow 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 also maintain the ability to monetize non-core assets, the proceeds from which could be used for funding our future growth requirements. During the year ended December 31, 2020, we executed multiple transactions, including sales of land and mineral assets, gas wells and coal reserves, which resulted in approximately $68 million in miscellaneous other income and gain on sales of assets. 

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 optimized 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, 2020, the PAMC included 657.9 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 12,940 Btu/lb, while production from the PRB, ILB, CAPP and the rest of NAPP averages approximately 8,700 Btu/lb, 11,300 Btu/lb, 12,000 Btu/lb and 12,500 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, 2020). Moreover, our remaining reserves have an average sulfur content of 2.40%, while production from the ILB averages 2.9% sulfur and production from the rest of NAPP averages 3.4% sulfur (again, based on EIA power plant delivery data for the three years ended June 30, 2020). With our high Btu content and low-cost structure, our 2020 total costs of tons sold averaged $1.47 per mmBtu, which is lower than any monthly average Louisiana Henry Hub natural gas spot price during the past 20+ 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 20.6 million tons of recoverable coal reserves that are sufficient to support more than 20 years of full-capacity production, and our 1.5 billion tons of Greenfield Reserves in NAPP, CAPP and ILB feature both thermal and metallurgical reserves and provide additional optionality for organic growth or monetization as market conditions allow.

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

The PAMC is the most productive and efficient coal mining complex in NAPP, averaging 7.14 tons of coal production per employee hour in 2019-2020, compared to 5.11 tons of coal production per employee hour for other currently-operating NAPP longwall mines. For the year ended December 31, 2020, the PAMC produced 7.21 tons of coal per employee hour, compared to an average of 4.90 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 $4 to $7 per ton for coal delivered to foreign consumers in Europe and India, up to $3 to $5 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 premium thermal and crossover metallurgical coal.

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 86% of our sales in 2020 were to customer companies that were in our 2019 portfolio, and all of our top domestic power plant customers in 2020 (which represent the ten plants to which we shipped approximately 400,000 tons or more of PAMC coal in 2020) 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 13.2% higher weighted average capacity factor than other NAPP rail-served plants in January through October 2020 (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 74% of our domestic coal shipments in 2020, 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 27%.

In addition to our robust domestic customer base, we also have favorable access to seaborne coal markets through our long-standing commercial relationship with a leading coal trading and brokering customer that maintains a broad market presence with international coal consumers. We have grown our exports of PAMC coal to the seaborne thermal and crossover metallurgical markets from an average of 5.5 million tons per year (or approximately 23% of our annual sales volume) in 2015-2016 to 7.0 million tons (or approximately 38% of our annual sales volume) in 2020.

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 both the thermal and metallurgical 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 2021, CONSOL Energy expects to invest $100 - $125 million in capital expenditures, excluding any spending on the Itmann Mine project. The Company continually evaluates potential acquisitions.

Detail Coal Operations

Recoverable Coal Reserves

The Company's estimates of recoverable coal reserves are estimated internally using the face positions of the PAMC’s longwall mines and the face position of the Itmann Mine's continuous mining section as of December 31, 2020. The December 31, 2020 reserves were estimated using the same techniques and assumptions as in prior years. These estimates are based on geologic data, coal ownership information and current and proposed mine plans. CONSOL Energy'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 mining recovery, preparation plant yield and product moisture content. 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 a coal seam. The ability to update or modify the estimates of the Company's recoverable coal reserves is restricted to qualified geologists and mining engineers and all modifications are documented.

“Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between “Proven (Measured) Reserves” and “Probable (Indicated) Reserves,” which are defined as follows:

Spacing of points of observation for confidence levels in the Company's reserve estimations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). CONSOL Energy's estimates for proven reserves have the highest degree of geologic assurance. Because of the well-known continuity of the Pittsburgh Coal Seam, estimates for proven reserves are based on points of observation that are equal to or less than 3,000 feet apart, and estimates for probable reserves are computed from points of observation that are between 3,000 feet and 7,920 feet apart.

The Company's estimates of recoverable coal reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.

The Company's recoverable coal reserves fall within the range of commercially marketed coal grades in the United States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, including sulfur content, ash content and heating value. Modern power plant boiler configurations can compensate for coal quality differences that occur. As a result, all of the Company's coal can be marketed for the electric power generation industry. In addition, some of the Company's reserves exhibit thermoplastic behavior suitable for cokemaking, which enables it, if market dynamics are favorable, to capture greater margins from selling this coal in the metallurgical market to cokemakers and steel manufacturers who utilize modern cokemaking technologies. The addition of this market adds additional assurance that CONSOL Energy's recoverable coal reserves are commercially marketable. 

At December 31, 2020, the Company had an estimated 2.2 billion tons of recoverable coal reserves. As of December 31, 2020, the PAMC included 657.9 million tons of recoverable coal reserves that are sufficient to support more than 20 years of full-capacity production. Estimates of the Company’s recoverable coal reserves have historically been estimated both by internal geologists and engineers and independent third parties. Reserve estimates and evaluation processes are periodically audited by independent third parties to ensure accuracy.

The Company’s recoverable coal reserves include 81.3 million tons of undeveloped reserves that are classified as high-vol, mid-vol or low-vol metallurgical coal. Additionally, worldwide demand for metallurgical coal allows some of our recoverable coal reserves, 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 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. We refer to these reserves as accessible. Accessible reserves are recoverable coal reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.

Some reserves may be accessible by more than one mine because of the proximity of many of our mines to one another. In the table below, the accessible reserves 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. Assigned and unassigned coal reserves are recoverable coal reserves which are either owned or leased. The leases have terms extending up to 30 years and 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, assigned reserves reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.

Pennsylvania Mining Complex

Pennsylvania Mining Complex. The Pennsylvania Mining Complex is located in Enon, 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. 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 current annual production capacity of the PAMC is approximately 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.

Bailey Mine. As of December 31, 2020, the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 108.2 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,900 Btus per pound and an approximate average pounds of sulfur dioxide per mmBtu of 4.42. 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, 2020, 2019 and 2018, the Bailey Mine produced 8.7, 12.2 and 12.7 million tons of coal, respectively. 

Enlow Fork Mine. As of December 31, 2020, the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 321.7 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,940 Btus 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, 2020, 2019 and 2018, the Enlow Fork Mine produced 5.7, 10.0 and 9.9 million tons of coal, respectively. 

Harvey Mine. As of December 31, 2020, the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 228.0 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,950 Btus per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.89. 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, 2020, 2019 and 2018, the Harvey Mine produced 4.4, 5.0 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.

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. The mine accesses the Pocahontas 3 seam (P3) 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, 2020, the Itmann Mine's assigned and accessible reserve base contained an aggregate of 20.6 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 0.99% sulfur, 7.6% ash, and 19.2% 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 year ended December 31, 2020, the Itmann Mine produced 25 thousand tons of coal. Production from the Itmann Mine is currently sold on a raw basis at the mine to a third-party buyer while the mine and facilities are being developed. The Company is currently evaluating plans to develop a dedicated coal preparation plant to process and handle the Itmann Mine's production. 

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

CONSOL ENERGY PENNSYLVANIA MINING COMPLEX

Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2020 and 2019

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

CONSOL ENERGY ITMANN MINE

Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2020 and 2019

The following table sets forth our assigned non-operating and unassigned recoverable coal reserves by region:

CONSOL Energy ASSIGNED Non-Operating and UNASSIGNED Recoverable Coal Reserves

as of December 31, 2020 and 2019

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 Proven and Probable Recoverable Coal Reserves

By Product (In Millions of Tons) as of December 31, 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, 2020, 2019 and 2018.

* Excludes advanced mining royalty payments received of $1,198, $2,289 and $2,805 during the years ended December 31, 2020, 2019 and 2018, 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, 2020, 99.9% 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, 2020, 2019 and 2018, 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 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:

Coal sales were impaired in 2020 as a result of weakened customer demand due to a warmer than normal winter followed by the COVID-19 pandemic, each of which reduced electricity consumption and, therefore, demand for our coal. Additionally, customer contract buyouts in 2020 impacted our sales performance. These partial contract buyouts involved negotiations to reduce the coal quantities several customers were obligated to purchase from us under their contracts in exchange for payment of certain fees to us, and did not impact forward contract terms. We sell coal produced by our mines and additional coal that is purchased by us for resale from other producers. 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. Approximately 68% of our 2018 coal sales were made to U.S. electric generators, 29% of our 2018 coal sales were made to export markets and 3% of our 2018 coal sales were made to other domestic customers. We had sales to approximately 29 customers from our 2020 coal operations. During 2020, three customers each comprised over 10% of our coal sales, aggregating approximately 55% of our sales. Annual metallurgical coal revenues for the past three years ranged from $56.2 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. The average contract term is between one to three years. As a normal course of business, efforts are made 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. For the year ended December 31, 2020, approximately 68% of all the coal we produced was sold under contracts with terms of one year or more.

We expect total consolidated Pennsylvania Mining Complex annual sales to be approximately 22-24 million tons for 2021. Coal pricing for contracts with terms of one year or less is generally fixed. Coal pricing for multiple-year agreements often provides the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:

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 2020 sales tons, approximately 60% were sold to U.S. electric generators, 38% were sold to export markets and 2% were sold to other domestic customers. Of the 38% of our 2020 sales tons sold to export markets, 18% were sold in the metallurgical market and 82% were sold in the electric power generation and industrial markets. In 2020, we derived greater than 55% of our total coal sales revenue from our top three customers. As of January 1, 2021, we had multiple sales agreements with these customers that expire at various times in 2021 through 2023.

During the past three years, our average realization (sales price per ton sold) for coal produced from the PAMC has decreased from $49.28/ton in 2018, to $47.17/ton in 2019, and to $41.31/ton in 2020. Pricing for our product depends strongly on conditions in the domestic thermal coal market, which accounted for at least 62% of our total sales volumes in each of 2018, 2019 and 2020.

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 thermal market and the export metallurgical market. 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.

Terminal Services

In 2020, approximately 10.1 million tons of coal were shipped through the CONSOL Marine Terminal owned by our subsidiary, CONSOL Marine Terminals LLC. Approximately 77% 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 east coast United States coal terminal served by two railroads, Norfolk Southern Corporation and CSX Transportation Inc. The CONSOL Marine Terminal has significant storage capacity of 1.1 million tons with more than thirty acres of capacity for stockpiles. The facility possesses extensive blending capabilities, and has handled approximately 11.5 million tons of coal per year on average over the past five years, with a potential maximum 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, and our sales and logistics specialists also negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for certain 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 with 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 from older, less efficient coal-fired powered generators. Federal and state mandates for increased use of electricity derived from renewable energy sources could 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.

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 industrial users of our coal are subject to extensive regulation regarding the environmental impact of their power generation activities, which could affect demand for our coal.

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 change their operations significantly 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 and 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 position.

In recent years, multiple regulations impacting our operations, or our customers' operations, have been subject to revision or repeal. However, the extent to which these regulations will take effect or survive future federal presidential administrations is uncertain. In addition, future 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, or expedite the retirements of fossil fuel fired electric generating units, which could have a material adverse effect on our business, financial condition and results of operations.

Under the Congressional Review Act, Congress also has the ability to revoke any final regulations promulgated by a federal agency within the past 60 legislative (not calendar) days. Given the change in the composition of the Senate, it is possible that environmental and other regulations could be revoked without having to undergo the regulatory rule-making process. The date of 'for the past 60 legislative days' will be fixed by Congress but is expected to fall sometime in mid- to late August 2021. Environmental regulations that affect coal mining operations - either directly or indirectly - that were promulgated after that period of time could be revoked by Congress through the Congressional Review Act.

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 or modification 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 focused on emissions from coal-fired electric generation facilities or coal mining 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 to operate 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 hazardous air pollutant (“HAP”) emissions, including mercury, for coal and oil-fired power plants. The EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) imposed MACT emissions limitations on HAPs, such as mercury, acid gas HAPs, HAP metals and organic HAPs for new and existing coal-fueled and oil-fueled electric generating plants. 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. The U.S. Supreme Court remanded to the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) to determine whether to allow the EPA to address the rule’s deficiencies or to vacate and nullify the rule. In April 2017, the D.C. Circuit granted the EPA's request to stay the case to allow the agency to fully review the 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 for the MATS Rule, as well as the related risk and technology review required by the CAA. Under the proposal, the emissions standards and other requirements of the MATS Rule would remain in place while the EPA's methodology for assessing the costs and benefits of the rule were being modified. In December 2015, while the EPA was addressing the Supreme Court's ruling, the D.C. Circuit denied a continued stay of the rule. 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 costs and benefits estimates of the rule, concluding that it is not “appropriate and necessary” to regulate hazardous air pollutants from power plants, and seeking 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. The Environment Executive Order signed on January 20, 2021 directs the EPA Administrator to “consider publishing for notice and comment a proposed rule suspending, revising, or rescinding” the May 2020 reconsideration of the MATS Rule by August 2021.

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”). Areas that are not in compliance with these standards are considered “non-attainment areas.” In recent years, the EPA has adopted more stringent NAAQS for these criteria pollutants, which could directly or indirectly impact mining operations through the designation of new non-attainment areas which could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans that require emission source identification and emission reduction plans. Final rules may require significant investment in emissions control technologies by our customers in the electric power generation industry, and could affect the demand for our coal. For example, in 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard. The final rule was challenged in the D.C. Circuit. On April 7, 2017, the EPA advised the D.C. Circuit that it intended to reconsider the final rule and the Court subsequently stayed the litigation pending further action by the EPA. In August 2018, the EPA ultimately decided not to revisit the rule. As a result, the D.C. Circuit lifted its stay of the 2015 ozone NAAQS rule imposing the 70 ppb ambient air quality standard while the EPA reviews the standards under an expedited review process. On October 31, 2019, the EPA published a draft policy assessment recommending that the 70 ppb ozone NAAQS be retained. On May 22, 2020, the EPA published notice of the Final Policy Assessment, followed by the proposed rule on August 14, 2020. The final rule retaining the 70 ppb ozone NAAQS was published on December 31, 2020. That rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. Although this final rule is not listed in the Environment Executive Order itself, it is listed in a fact sheet that was released by the Biden transition team on the morning of the inauguration that lists environmental rules that should be reconsidered in light of the Environment Executive Order. The EPA also finalized a decision to retain the NAAQS for particulate matter, which was published on December 18, 2020. This rule was also challenged in the D.C. Circuit and is on the list of regulations that the Biden Administration intends to reconsider.

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. 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 state implementation plans that would establish additional requirements beyond the existing CSAPR Update. The Close-Out Rule was challenged by several states and other entities in the D.C. Circuit. In a September 13, 2019 ruling, the D.C. Circuit remanded the 2016 CSAPR Update Rule to the EPA, finding that rule is inconsistent with the CAA. In a subsequent October 1, 2019 ruling, the CSAPR Close-Out Rule was vacated. On October 30, 2020, the EPA published the proposed Revised CSAPR that would establish new or amend existing Federal Implementation Plans (FIPs) to revise state emission budgets to reflect additional emissions reductions from EGUs beginning with the 2021 ozone season and concluding in 2024. It is unknown at this time whether the Biden Administration will finalize this rulemaking.

Regulation of 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 ultimately stayed by the U.S. Supreme Court, pending EPA reconsideration and repeal. In August 2018, the EPA published a proposed rule, the Affordable Clean Energy (“ACE”) rule, to replace the CPP.

The CPP was formally repealed with promulgation of the final ACE rule, which 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 state implementation plans to implement the rule, and revises CAA section 111(d) regulations to give states greater authority regarding these plans. States may 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 January 19, 2021 ruling, the ACE rule was vacated in its entirety by the D.C. Circuit and remanded to the EPA. It is unclear at this time what the Biden Administration will do in light of the court's decision vacating the ACE rule.

Final New Source Performance Standards (“NSPS”) for 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 comment period for the proposed rule closed on February 19, 2019. On January 12, 2021, the EPA finalized its “Pollutant Specific Significant Contribution Finding for Greenhouse Gas Emissions from New, Modified and Reconstructed Electric Utility Generating Units,” which provides a framework for determining when standards are appropriate for emissions of greenhouse gases from specific source categories under CAA section 111(b)(1)(A). The framework sets an emissions threshold of 3 percent of total gross U.S. GHG emissions from a stationary source category as the criterion for determining pollutant-specific significance for purposes of CAA section 111(b). In this action, the EPA determined that the EGU source category GHG emissions are significant and warrant regulation. The rule will likely be subject to further legal challenge and legislative review. The EPA has not finalized the portion of the proposed reconsideration rule that would have modified the NSPS requirements to be based on use of a supercritical boiler, and it is unlikely that the Biden Administration will finalize this proposal.

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, and (iii) a reduction or elimination of new coal-fired power plant construction in certain countries.

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.

Since 2011, the EPA has required underground coal mines and certain support facilities exceeding a minimum GHG emission threshold to report emissions annually under the Mandatory GHG Reporting Rule. These emissions are currently classified as fugitive emissions associated with coal extraction and 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, some states, governors, mayors and businesses have committed to broad GHG reduction goals and requirements. For instance, 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 all cap-and-trade scenarios, power generators 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, legislators in the Pennsylvania General Assembly introduced House Bill 2025 that, if approved, would require legislative approval from both chambers of the General Assembly for any action imposing a revenue-generating tax or fee intended to reduce CO₂ emissions. House Bill 2025 was approved by the Pennsylvania House and Pennsylvania Senate but was subsequently vetoed by Governor Wolf on September 24, 2020. On November 7, 2020, the Pennsylvania Environmental Quality Board (EQB) 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). While the Wolf administration intends to finalize the rule on or before January 1, 2022, the proposed regulation will be subject to further analysis under Pennsylvania's Regulatory Review Act, Commonwealth Attorneys Act and the Climate Change Act, and will likely be subject to legal and legislative challenges. If implemented, the proposed CO₂ Budget Trading Program regulation could result in decreased demand or decreased prices for our domestic coal.

At both the state and federal levels, environmental organizations and state 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 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.

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, related to the installation of emissions control technologies, the expense associated with the purchase of emissions reduction credits to comply with future emissions trading programs, the expense associated with any future carbon tax, or reduced consumption by 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, primarily through permitting. 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 often require (1) treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, sulfates, selenium and dissolved solids and (2) requirements to dispose of produced wastes at approved disposal facilities.

In order to obtain a permit for certain coal mining activities, including 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, as well as a corresponding permit from the state regulatory authority under Section 401 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. All permits associated with the placement of dredge or fill material subject to minimum thresholds require appropriate mitigation. Permit holders must receive explicit authorization from the ACOE before proceeding with mining activities, which could result in time or cost burdens to our operations.

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 streams that are protective of water quality standards. For wastewater 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.

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. See Item 3, “Legal Proceedings,” regarding certain actions pertaining to our operations.

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. This rule was quickly challenged and nationwide implementation was blocked by a federal appeals court. The Clean Water Rule would impose additional permitting obligations on the Company's operations by increasing the number of waterbodies subject to CWA permitting and other regulations. On February 28, 2017, President Trump issued an executive order prompting the EPA and ACOE to consider replacing the blocked Clean Water Rule. On December 11, 2018, the EPA and the ACOE proposed a new regulation to determine which waterbodies are subject to federal jurisdiction. A final rule repealing the 2015 definition of “Waters of the United States” (“WOTUS”) became effective on December 23, 2019. The repeal resets a consistent, nationwide regulatory standard to the previous pre-2015 regulations. On April 21, 2020, the EPA and ACOE published the Navigable Waters Protection Rule (“NWPR”), which became effective on June 22, 2020 in all states except Colorado, where a preliminary injunction preventing implementation of the rule remains in place. The NWPR is currently subject to ongoing litigation, which is expected to continue in multiple courts.

On November 3, 2015, the EPA published the final Effluent Limitations Guidelines and Standards (“ELG”) rule, revising the regulations for the Steam Electric Power Generating category, which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants. On September 13, 2017, the EPA finalized a rule postponing for two years certain applicability dates for specific waste streams subject to the effluent limitations. On November 22, 2019, the EPA published its proposed revisions to the 2015 final ELG rule, while establishing a voluntary incentive program which provides power plants until December 31, 2028 for retirement or to 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. The final ELG rule was published on October 13, 2020, with an effective date of December 14, 2020.

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 permit issuance is largely at the discretion of the regulatory authorities and is related to the size and complexity of the operation seeking approval. 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. In addition, mining permits can be delayed, refused, or revoked if any entity under common ownership or control have unabated permit violations, including the mining and compliance history of officers, directors, and principal owners of the entity seeking permit approval.

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, 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, 2020, we posted an aggregated $564 million in surety bonds for reclamation purposes, as well as approximately $245 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 current fee is $0.12 per ton for underground mined coal. This fee is currently scheduled to be in effect until September 30, 2021. We recognized expense related to Abandoned Mine Reclamation Fund fees of $2 million for the year ended December 31, 2020.

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. However, we do not believe the ESA would materially or adversely affect our mining operations under current approved mining plans. If more stringent or protective measures were required, or if additional critical habitat areas were designated, our operations could be exposed to additional requirements and expense, or delayed approval timeframes. In August 2018, the Department of the Interior issued three proposed rules intended to update and streamline 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. These rules, which became effective on September 26, 2019, are subject to challenge from several states and environmental groups. Additional rules were promulgated in December 2020 regarding noncritical habitat, which could also be subject to judicial challenge.

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 June 2018, the White House Council on Environmental Quality (“CEQ”) issued an Advance Notice of Proposed Rulemaking on NEPA seeking to streamline the NEPA process, while also minimizing unnecessary litigation, cost, and delay for project proponents. The final NEPA update rule was published on July 16, 2020. Separately, on June 26, 2019, 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 has not yet been 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”. Although the NEPA update rule became effective September 14, 2020, it is currently subject to legal challenge. The Environment Executive Order directs the Council on Environmental Quality to rescind the 2019 Draft Guidance.

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 sites 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 in the event a hazardous substance is released 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. RCRA is particularly important in the coal industry because it regulates coal combustion residuals - byproducts of coal combustion. In April 2015, the EPA published coal combustion residuals regulations under RCRA for the disposal of coal combustion residuals from electric utilities and independent power producers (the “coal combustion residuals rule”). Importantly, coal combustion residuals are regulated under RCRA as “non-hazardous” waste and avoid the stricter, costlier regulations under RCRA's “hazardous” waste rules. On December 2, 2019, the EPA published the first of a multi-part rulemaking amending the national minimum criteria for existing and new coal combustion residual impoundments. The EPA published its second rulemaking proposal on February 20, 2020 to establish a federal permitting program for states and territories that do not have an approved permitting program for the disposal of coal combustion residuals in surface impoundments and landfills under RCRA. On August 28, 2020, the EPA published multiple amendments to the rule mandating closure of unlined impoundments, with deadlines to initiate closure between April 11, 2021 and October 17, 2028, depending on site specific circumstances. On October 16, 2020, the EPA finalized provisions proposed in Part B of the rule, providing for compliance through an alternative liner demonstration provision. The rule and its amendments are subject to ongoing legal challenge. The coal combustion residuals rules impose new requirements at existing coal combustion residuals impoundments and landfills that would generally increase the cost of coal combustion residuals management or require facility closure. The combined effect of the coal combustion residuals rule and ELG regulations (discussed above) has compelled power generating companies to close existing ash ponds and may force the closure of certain older 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:

The Patient Protection and Affordable Care Act (“PPACA”) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner's death. The changes have increased the cost to us of complying with the Federal Black Lung Benefits Act. In addition to the federal legislation, we are also liable under various state statutes for our portion of black lung claims.

Other State and Local Laws Related to Our Coal Business

Ownership of Coal Rights. The Company acquires ownership or leasehold rights to coal properties prior to conducting operations on those properties. As is customary in the coal industry, we have generally conducted only a summary review of the title to coal rights that are not in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control of coal rights. Given our experience as a coal producer, we believe we have a well-developed ownership position relating to our coal control. Prior to the commencement of development operations on coal properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We are typically responsible for the cost of curing any title defects. We have completed title work on substantially all of our coal producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.

Employees

At December 31, 2020, we had 1,494 employees, of which 36 CONSOL Marine Terminal employees were represented by a collective bargaining agreement.

Available Information

We maintain a website at www.consolenergy.com. We will make available, free of charge, on this website our future annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the Securities and Exchange Commission (“SEC”), and are also available at the SEC’s website, www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.

You should carefully consider the following risks and other information in this Annual Report on Form 10-K in evaluating us and our common stock. The risk factors generally have been separated into two groups: risks related to our business and risks related to our common stock and the securities market.

Any of the following risks could materially and adversely affect our financial condition, results of operations or cash flows. Our operations could be affected by various risks, many of which are beyond our control. Based on current information, we believe that the following list identifies the most significant risk factors that could affect our financial condition, results of operations or cash flows. There may be additional risks and uncertainties that adversely affect our financial condition, results of operations or cash flows in the future that are not presently known, are not currently believed to be material, or are not identified below because they are common to all businesses. Past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods. For more information, see “Forward-Looking Statements.”

Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations and financial results:

Risks Related to Our Business

Risks Related to Our Common Stock and the Securities Market

Risks Related to Our Business

Deterioration in the global economic conditions in any of the industries in which our customers operate, or a worldwide financial downturn, or negative credit market conditions may have a materially adverse effect on our liquidity, results of operations, cash flows, business and financial condition that we cannot predict.

Economic conditions in a number of industries in which our customers operate, such as electric power generation and steelmaking, substantially deteriorated in recent years and reduced the demand for coal. Renewed or continued weakness in the economic conditions of any of the industries we serve or are served by our customers could adversely affect our business, financial condition, results of operations, cash flows and liquidity in a number of ways. For example:

Prices for coal are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand available for our coal, weather and the price and availability of alternative fuels. A substantial or extended decline in the prices we receive for our coal will adversely affect our business, results of operations, financial condition and cash flows.

Our financial results are significantly affected by the prices we receive for our coal and depend, in part, on the margins that we receive on sales of our coal. Our margins reflect the price we receive for our coal over our cost of producing and transporting our coal. Prices and quantities under our multi-year sales contracts are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or re-opened. The expectation of future prices for coal depends upon many factors. In addition, demand can fluctuate widely due to a number of matters beyond our control, including:

Our business, results of operations and financial condition may be adversely affected by the outbreak of the novel coronavirus (COVID-19).

The COVID-19 pandemic began to adversely impact our business and operations late in the first quarter of 2020. The effects of the continuing pandemic and related governmental response could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in demand for coal and overall global economic activity.

The demand for coal experienced unprecedented decline toward the end of the first quarter of 2020, which continued through the third quarter of 2020, driven by widespread government-imposed lockdowns caused by the COVID-19 pandemic, which significantly reduced electricity consumption and therefore, demand for our coal. This decline in coal demand negatively impacted our operational, sales and financial performances in 2020, and we expect that this negative impact could continue as the pandemic continues.

While some government-imposed shut-downs of non-essential businesses in the United States and abroad have been phased out, there is a possibility that such shut-downs may be reinstated as COVID-19 continues to spread rapidly. We expect that depressed demand for our coal will continue for so long as there is a widespread, government-imposed shut-down of business activity. Depressed demand for our coal may also result from a general recession or reduction in overall business activity caused by COVID-19. Additionally, some of our customers have already attempted, and may in the future attempt, to invoke force majeure or similar provisions in the contracts they have in place with us in order to avoid taking possession of and paying us for our coal that they are contractually obligated to purchase. Sustained decrease in demand for our coal and the failure of our customers to purchase coal from us that they are obligated to purchase pursuant to existing contracts would have a material adverse effect on our operations and financial condition. The continued spread of COVID-19 has caused increased volatility in the global capital markets. Such volatility increases the cost of, and decreases access to, capital. If the Company needs to access the capital markets to fund its operations, such capital could be prohibitively expensive which could cause the Company to pursue alternative sources of funding for its operations and working capital. COVID-19 may cause some of our suppliers to fail to deliver the quantities of supplies we need or fail to deliver such supplies in a timely manner. The failure to receive any such supplies could inhibit our ability to operate our mines or otherwise run our business. The risks associated with a potential COVID-19 outbreak among our employees could adversely affect our ability to operate. Additionally, our ability to ship our coal domestically or abroad could be impaired by disruptions in our global transportation network resulting from the COVID-19 pandemic.

The extent to which COVID-19 may adversely impact our results of operations, cash flows and financial condition depends on future developments, which are highly uncertain and unpredictable, including new information concerning the severity of the outbreak and the pace and effectiveness of vaccination efforts or actions globally to contain or mitigate its effects. The Company will continue to take the appropriate steps to mitigate the impact on the Company's operations, liquidity and financial condition.

Any significant downtime of our major pieces of mining equipment, including our central preparation plant, or any inability to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs, could impair our ability to supply coal to our customers and materially and adversely affect our results of operations.

We depend on several major pieces of mining equipment to produce and transport our coal, including, but not limited to, longwall mining systems, continuous mining units, our preparation plant and related facilities, conveyors and transloading facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost, which would impact our ability to produce and transport coal and materially and adversely affect our business, results of operations, financial condition and cash flows. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment or the cancellation of our supply contracts under which we obtain equipment could limit our ability to obtain these supplies or equipment.

All of the coal from the PAMC, which accounts for more than 99% of our coal production, is processed at a single preparation plant and loaded on to rail cars using a single train loadout facility. If either of our preparation plant or train loadout facility suffers extended downtime, including from major damage, or is destroyed, our ability to process and deliver coal to our customers would be materially impacted, which would materially adversely affect our business, results of operations, financial condition and cash flows.

Additionally, coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operating costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel in the mining process. If the price of steel or other materials increases substantially or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially and adversely impact our business, financial condition, results of operations and cash flows.

If our coal customers do not extend existing contracts or do not enter into new multi-year coal sales contracts on favorable terms, profitability of our operations could be adversely affected.

During the year ended December 31, 2020, approximately 68% of the coal the Company produced was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or terminated, if force majeure is exercised, or if we are unable to replace or extend the contracts or new contracts are priced at lower levels, our profitability would be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have existing contractual obligations, our revenues will decrease and we may have to reduce production at our mines until such customers honor their contractual obligations and begin accepting shipments of our coal again.

The profitability of our multi-year sales coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, during periods of declining market prices, provisions in our long-term coal contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price and electric power price volatility. As a result, we may not be able to obtain long-term agreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, which may reduce our profitability.

We have customer concentration, so the loss of, or significant reduction in, purchases by our largest coal customers could adversely affect our business, financial condition, results of operations and cash flows.

We are exposed to risks associated with an increasingly concentrated customer base both domestically and globally. We derive a significant portion of our revenues from three domestic customers, each of which accounted for over 10% of our total coal sales revenue and aggregated approximately 55% of our coal sales in fiscal year 2020. While the majority of our production is directed toward our established base of domestic power plant customers, many of which are secured through annual or multi-year sales contracts, we also have continued to diversify our portfolio by placing a growing portion of our production in the export markets. 

There are inherent risks whenever a significant percentage of total revenues are concentrated with a limited number of customers. Revenues from our largest customers may fluctuate from time to time based on numerous factors, including market conditions, which may be outside of our control. If any of our largest customers experience declining revenues due to market, economic or competitive conditions, we could be pressured to reduce the prices that we charge for our coal, which could have an adverse effect on our margins, profitability, cash flows and financial position. If any customers were to significantly reduce their purchases of coal from us, including by failing to buy and pay for coal they committed to purchase in sales contracts, our business, financial condition, results of operations and cash flows could be adversely affected.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to collect payments from our customers for coal sold and delivered could be impaired if their creditworthiness declines or if they fail to honor their contracts. Because a large portion of our sales are concentrated to a few material customers, if the creditworthiness of a significant customer declines or the customer significantly delays payments to us, our business, cash flows and financial condition could be materially and adversely affected. Furthermore, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation or if we terminate a relationship with a significant customer due to credit risks, our revenue could decrease materially and we may have to reduce production at our mines until our customers’ contractual obligations are honored or we are able to replace a significant customer. In addition, our borrowing capacity under our receivables financing arrangement could be reduced if we experience prolonged and significant delays in payments by one or more material customers.

Our inability to acquire or develop additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability.

Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics that our customers desire. Because our reserves decline as we mine our coal, our future profitability depends upon our ability to acquire additional coal reserves and surface land needed to ensure the reserves are economically recoverable to replace the reserves we produce. If we fail to acquire, gain access to or develop sufficient additional reserves over the long term to replace the reserves depleted by our production, our existing reserves will eventually be depleted, which may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Decreases in demand for electricity and changes in coal consumption patterns of electric power generators could adversely affect our business.

Our business is closely linked to demand for electricity, and any changes in coal consumption by U.S. or international electric power generators would likely impact our business over the long term. According to the EIA, in 2020, the domestic electric power sector accounted for approximately 91% of total U.S. coal consumption. In 2020, the Pennsylvania Mining Complex sold approximately 60% of its coal to U.S. electric power generators, and we have annual or multi-year contracts in place with many of these electric power generators for a significant portion of our future production. The amount of coal consumed by the electric power generation industry is affected by, among other things:

Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. 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 potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from 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. A decrease in coal consumption by the electric power generation industry could adversely affect the price of coal, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Other factors, such as efficiency improvements associated with new appliance standards in the buildings sectors and overall improvement in the efficiency of technologies powered by electricity, have slowed electricity demand growth and may contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.

The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal, and any significant damage to the CONSOL Marine Terminal that impacts its use could impair our ability to supply coal to our customers.

Transportation logistics play an important role in allowing us to supply coal to our customers. Any significant delays, interruptions or other limitations on the ability to transport our coal could negatively affect our operations. Our coal is transported from our mines primarily by rail. To reach markets and end customers, our coal may also be transported by barge or by ocean vessels loaded at terminals, including our CONSOL Marine Terminal. Disruption of transportation services because of weather-related problems, strikes, lock-outs, terrorism, governmental regulation, third-party action or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. In addition, transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuation in the price of diesel fuel and demurrage, could make our coal less competitive. Any disruption of the transportation services we use or increase in transportation costs could have a materially adverse effect on our business, financial condition, results of operations and cash flows. Disruption in shipment levels over longer periods of time at the CONSOL Marine Terminal could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and results of operations.

Competition within the coal industry may adversely affect our ability to sell coal. Increased competition or a loss of our competitive position could adversely affect our sales of, or prices for, our coal, which could impair our profitability. In addition, foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete with other producers primarily on the basis of price, coal quality, transportation costs and reliability of delivery. We compete with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to electric power generators. We also compete with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies such as natural gas and petcoke, and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric, wind and solar power.

We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition. The coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. As a result, a substantial portion of coal production is from companies that have significantly greater resources than we do. Current or further consolidation in the coal industry or current or future bankruptcy proceedings of coal competitors may adversely affect us. In addition, increases in coal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. If overcapacity results, the prices of and demand for our coal could significantly decline, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, we face competition from foreign producers that sell their coal in the export market. Potential changes to international trade agreements, trade concessions 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 with 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 foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign 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.

A significant portion of our production is sold in international markets, which exposes us to additional risks and uncertainties.

For the fiscal years ended December 31, 2020, 2019 and 2018, approximately 35%, 35% and 29%, respectively, of our annual coal revenue was derived from customers who exported our coal outside of the United States. Exports to Asia represent the majority of those sales. We believe that international markets will continue to account for a significant percentage of our revenue as we seek international expansion opportunities. The international markets are subject to a number of material risks, including, but not limited to:

Our sales are also affected by general economic conditions in our international markets. A prolonged economic downturn in international markets could have a material adverse effect on our business. Negative developments in one or more countries or regions in which our coal is exported could result in a reduction in demand for our coal, the cancellation or delay of orders already placed, difficulties in producing and delivering our products, difficulty in collecting receivables or a higher cost of doing business, any of which could negatively impact our business, financial condition, cash flows and results of operations. In addition, we may be exposed to legal risks under the laws of the countries outside the U.S. in which we do business, as well as the laws of the U.S. governing our business activities in those other countries, such as the U.S. Foreign Corrupt Practices Act.

The Company intends, if possible, to offset any potential adverse impact from various international risks (for example, tariffs) that may be imposed by governments in the countries in which one or more of the Company's end users are located by reallocating its customer base to other countries or to the domestic U.S. markets.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when it is burned. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users needed to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase) or switch to other fuels, each of which has limitations. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. The Cross State Air Pollution Rule (“CSAPR”), the Mercury and Air Toxics Standard Rule (“MATS”) and the New Source Performance Standards (“NSPS”) for Fossil Fuel-Fired Electricity Utility Generating Units (“EGUs”) are examples of such rulemakings promulgated under the Clean Air Act. For more information, please see “Laws and Regulations” under Item 1 above.

Regulation to address climate change (particularly greenhouse gas emissions) and uncertainty regarding such regulation may increase our operating costs, reduce the value of our coal assets and adversely impact the market for coal.

The issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity (especially the emissions of GHGs such as carbon dioxide and methane). Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere by coal end-users, such as coal-fired electric power plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in regional cap-and-trade programs like the RGGI in the northeastern U.S. Any significant legislative changes at the international, national, state or local levels could significantly affect our ability to produce and sell our coal and develop our reserves, could increase the cost of the production and sale of coal and could materially reduce the value of our coal and coal reserves.

Apart from governmental regulation, investment banks based both domestically and internationally have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants. In addition, there have been efforts in recent years affecting the investment community, including investment advisers, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities, encouraging the consideration of environmental, social and governance (“ESG”) practices of companies in a manner that negatively affects coal companies, and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-coal fuel sources, including natural gas and/or alternative energy sources, could cause coal prices and sales of our coal to materially decline and could cause our costs to increase. Further, climate change itself may cause more extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our services and increase our costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Furthermore, adoption of comprehensive legislation or regulation focusing on climate change or GHG emission reductions for the United States or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate coal-fired electric power generation plants and make coal less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas and/or alternative energy sources could gain added economic benefits versus coal-fueled power generation, especially if such regulation or legislation makes our coal more expensive as a result of increased compliance, operating and maintenance costs. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. Our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal and comply with future GHG emission standards. Although we cannot predict the ultimate impact of any legislation or regulation, it is likely that any future laws, regulations or other policies aimed at reducing GHG emissions will negatively impact demand for our coal and could also negatively affect the value of our reserves and other assets.

We may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. For instance, we have been named as a defendant in litigation brought by the City of Baltimore seeking to hold us and other energy companies liable for the effects of climate change caused by the release of GHGs. The outcome of this litigation is uncertain, and we could incur substantial legal costs associated with defending this and similar lawsuits in the future. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for coal and may restrict our coal operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities, relating to protection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the installation of various safety equipment in our mines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position.

In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities, or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations and competitive position. 

Our business involves many hazards and operating risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our results of operations, financial condition and cash flows.

Our coal mining operations are underground mines. Underground mining and related processing activities present inherent risks of injury or death to persons, damage to property and equipment and other potential legal or other liabilities. Our mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time, thereby adversely affecting our operating results. In addition, if an operating risk occurs in our mining operations, we may not be able to produce sufficient amounts of coal to deliver under our multi-year coal contracts. Our inability to satisfy contractual obligations could result in our customers initiating claims against us or canceling their contracts. The operating risks that may have a significant impact on our coal operations include:

The occurrence of any of these risks at our coal mining operations could adversely affect our ability to conduct our operations or result in substantial loss to us, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows. In addition, the occurrence of any of these events in our coal mining operations which prevents our delivery of coal to a customer and which is not excusable as a force majeure event under our coal sales agreement could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the coal sales agreement, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Although we maintain insurance for a number of risks and hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our coal operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Moreover, a significant mine accident could potentially cause a mine shutdown. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and failure to obtain adequate insurance coverages could both have a material adverse effect on our business and results of operations.

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers' compensation costs, coal leases and other obligations. The costs of surety bonds have fluctuated in recent years while the market terms of such bonds have generally become less favorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and reclamation more stringent. Because we are required by federal and state law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. Additionally, coal and other mining companies are increasingly struggling to obtain adequate insurance coverage for their business and operations. Our failure to obtain adequate insurance coverages could have a material adverse effect on our business and results of operations. Beginning in 2019, the insurance markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and fewer providers willing to underwrite policies and surety bonds. Terms have generally become more unfavorable, including the amount of collateral required to secure surety bonds. Further cost burdens on our ability to maintain adequate insurance and bond coverage may adversely impact our operations, financial position and liquidity. 

Substantially all of our operating mines are part of a single mining complex and are principally located in the Northern Appalachian Basin, making us vulnerable to risks associated with operating in a single geographic area.

Although we began production at the Itmann Mine, located in CAPP in Wyoming County, West Virginia in 2020, substantially all of our mining operations are conducted at a single mining complex located in NAPP in southwestern Pennsylvania and northern West Virginia. The geographic concentration of most of our operations at the Pennsylvania Mining Complex may disproportionately expose us to disruptions in our operations if the region experiences adverse conditions or events, including severe weather, transportation capacity constraints, constraints on the availability of required equipment, facilities, personnel or services, significant governmental regulation or natural disasters. If any of these factors were to impact NAPP more than other coal producing regions, our business, financial condition, results of operations and cash flows will be adversely affected relative to other mining companies that have a more geographically diversified asset portfolio.

Our mines are located in areas containing oil and natural gas shale plays, which may require us to coordinate our operations with oil and natural gas drillers and transporters.

Substantially all of our coal reserves are in areas containing shale oil and natural gas plays, including the Marcellus Shale, which are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If we have received a permit for our mining activities, then while we may have to coordinate our mining with such oil and natural gas drillers and transporters, our mining activities will have priority over any oil and natural gas drillers and transporters with respect to the land covered by our permit. Oil and natural gas drillers and transporters may be subject to law and regulations that are enforced by regulators that do not have jurisdiction over our activities. Any conflict between our rights and the enforcement actions by any regulator of oil or natural gas-specific rights that conflict with our rights to mine could result in additional costs and possible delays to mining.

For reserves outside of our permits, we engage in discussions with drilling and transport companies on potential areas on which they can drill that may have a minimal effect on our mine plan. If a well is in the path of our mining for coal on land that has not yet been permitted for our mining activities, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater than that of a vertical well. Horizontal wells with multiple laterals extending from the well pad may access larger oil and natural gas reserves than a vertical well, which would typically result in a higher cost to acquire. The cost associated with purchasing oil and natural gas wells that are in the path of our coal mining activities could likewise make mining through those wells uneconomical, thereby effectively causing a loss of significant portions of our coal reserves, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

In order to maintain, grow and diversify our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our financial leverage could increase.

In order to maintain, grow and diversify our business, we will need to make substantial capital expenditures to fund our share of capital expenditures associated with our mines, acquisitions or other business development initiatives. Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations requires substantial capital expenditures. While a significant amount of the capital expenditures required to build out our mining infrastructure has been spent, we must continue to invest capital to maintain or to increase our production. Decisions to increase our production levels could also affect our capital needs. Our production levels may decrease or may not be able to generate sufficient cash flow, or we may not have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional equity securities. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control, such as financial institutions abandoning the thermal coal sector. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant stockholder dilution.

Our securities may be excluded from consideration by certain investment funds and certain investors may have a negative perception of us due to being a coal producer.

Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based upon ESG or “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company's sustainability score as a reputational or other factor in making an investment decision. Companies in the energy industry, and in particular those focused on coal, natural gas or petroleum extraction and refining, often perform less well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities, both debt and equity, being excluded from the portfolios of certain investment funds and investors. Additionally, many investment funds and investors are beginning to avoid securities issued by any company in the coal, natural gas or petroleum extraction or refining business, regardless of their particular ESG or sustainability score. As such, this could restrict our access to capital to fund our continuing operations and growth and diversification opportunities.

New or existing tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

New or existing tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows, either directly or indirectly through various adverse impacts on our significant customers. During the last several years, the Trump Administration imposed tariffs on steel and aluminum and a broad range of other products imported into the U.S. In response to the tariffs imposed by the U.S., the European Union, Canada, Mexico and China have announced tariffs on U.S. goods and services. Although some of these tariffs have been rescinded or suspended, these tariffs, along with any additional tariffs or trade restrictions that may be implemented by the U.S. or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the United States or other potentially adverse economic outcomes. Additionally, we sell coal into the export thermal market and the export metallurgical market. Accordingly, our international sales may also be impacted by the tariffs and other restrictions on trade between the U.S. and other countries. While tariffs and other retaliatory trade measures imposed by other countries on U.S. goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows.

We may be unsuccessful in finding suitable acquisition targets or integrating the operations of any future acquisitions, including acquisitions involving new lines of business, with our existing operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we may evaluate and acquire assets and businesses that we believe complement our existing assets and business. However, our ability to grow our business through acquisitions may be limited by both our ability to identify appropriate acquisition candidates and our financial resources, including our available cash and borrowing capacity. Additionally, the assets and businesses we acquire may be dissimilar from our existing lines of business. Acquisitions may require substantial capital or the incurrence of substantial indebtedness, and potentially may not be on favorable terms. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including the following:

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Entry into certain lines of business may subject us to new laws and regulations with which we are not familiar, and may lead to increased litigation and regulatory risk. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions. If a new business generates insufficient revenue or if we are unable to efficiently manage our expanded operations, our results of operations may be adversely affected.

We must obtain, maintain and renew governmental permits and approvals which, if we cannot obtain in a timely manner, would reduce our production, cash flow and results of operations.

Our coal production is dependent on our ability to obtain various federal and state permits and approvals to mine our coal reserves. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators. Under Section 404 of the Clean Water Act, the Army Corps of Engineers (“Corps”) issues permits for the discharge of dredged or fill material into regulated navigable waters and wetlands. Corps permits are required for construction of slurry ponds, refuse areas, impoundments, and for various other mining activities. The Section 404 permitting process has become subject to increasingly stringent regulatory requirements and challenges by environmental organizations. In addition, the public, including non-governmental organizations and individuals, has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. It is possible that all permits required to commence new operations, or to expand or continue operations at existing facilities, may not be issued or renewed in a timely manner, or may not be approved at all. Furthermore, permits could be issued with operating requirements or special conditions that increase the cost of operations. Any of these circumstances could have significant negative effects and could materially and adversely affect our results of operations and cash flows.

Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors, under certain circumstances, have the ability to order our operations to be shut down based on safety considerations.

The Federal Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose stringent health and safety standards on mining operations. Regulations that have been adopted are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures and other matters. States in which we operate have programs for mine safety and health regulation and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations, and potentially lead to penalties for the violation of such requirements, creating a significant effect on operating costs and productivity. In addition, government inspectors, under certain circumstances, have the ability to order our operation to be shutdown based on safety considerations. If an incident were to occur at one of our coal mines, it could be shut down for an extended period of time and our reputation with our customers could be materially damaged.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages, as well as for the investigation and clean-up of soil, surface water, groundwater and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.

Our operations include coal refuse disposal areas, slurry impoundments and other water retaining or dam structures classified as “high” or “significant” hazards, depending on the extent of damage or loss of life that could occur in the event of a failure. A failure of these structures would result in liabilities that could have a material impact on our business.

We maintain coal refuse disposal areas (“CRDAs”), slurry impoundments and other water retaining or dam structures that are active or in various stages of reclamation at the Pennsylvania Mining Complex and at certain legacy properties. Such areas and impoundments are subject to extensive regulation and are designed, constructed, operated and maintained according to stringent environmental, structural and safety standards. In addition to routine inspections conducted by multiple regulatory authorities, these facilities are also inspected by qualified third-party inspectors and are separately certified by an independent professional engineer. Structural failure of a CRDA, slurry impoundment or other dam structure classified as a high or significant hazard could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries, property damages, injuries to wildlife or loss of life. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of these structures were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, claims for personal injury or loss of life, and claims for physical property damage, as well as fines and penalties. These events could materially and adversely impact our business, financial condition, results of operations and cash flows.

We have asset retirement obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

The Surface Mining Control and Reclamation Act (“SMCRA”) and various state laws establish operational, reclamation and closure standards for all our coal mining operations and require us, under certain circumstances, to plug natural gas wells. We accrue for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total asset retirement obligations, which are based upon permit requirements and our experience, were approximately $249 million at December 31, 2020. The amounts recorded are dependent upon a number of variables, including the estimated future expenditures, estimated mine lives, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient, our future operating results could be adversely affected.

Under SMCRA, we are required to obtain surety bonds or other acceptable security to secure payment of our asset retirement obligations. In most states where we have operating and/or non-operating mines, including Pennsylvania, we are required to post bonds for the full cost of coal mine reclamation. Other states, such as West Virginia, maintain an alternative bond system for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (“Special Reclamation Fund”) funded by a per ton fee on coal mined in the state which is used to supplement the site specific bonds if needed in the event of bond forfeiture. If these states were to move to full cost bonding in the future, individual mining companies and/or surety companies could exceed bonding capacity, resulting in the need to post cash or letters or credit, which reduces operating capital and liquidity.

To date, we have been able to post surety bonds to secure our reclamation obligations. However, the costs of surety bonds have fluctuated in recent years and the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and reclamation more stringent. If our creditworthiness declines, states may seek to require us to post letters of credit or cash collateral to secure those obligations, or we may be unable to obtain surety bonds, in which case we would be required to post letters of credit. Additionally, the sureties that post bonds on our behalf may require us to post security in order to secure the obligations underlying these bonds. Posting letters of credit in place of surety bonds or posting security to support these surety bonds would have an adverse effect on our liquidity. Furthermore, because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety, and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

We face uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Coal reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of production and selling. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our coal reserve information on geologic data, coal ownership information and current and proposed mine plans. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. There are numerous uncertainties inherent in estimating quantities and qualities of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a natural gas well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells with multiple laterals extending from the well pad may access larger natural gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing natural gas wells which are in the path of our coal mining may make mining through those wells uneconomical, thereby effectively causing a loss of significant portions of our coal reserves.

Each of the factors which impacts reserve estimation may vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal reserves. Additionally, our estimates of coal reserves may be adversely affected in future fiscal periods by the SEC's recent rule amendments revising property disclosure requirements for publicly-traded mining companies. We will be required to comply with these new rules when reporting for the 2021 fiscal year.

Defects may exist in our chain of title for our undeveloped coal reserves where we have not done a thorough chain of title examination of our undeveloped coal reserves. We may incur additional costs and delays to mine coal because we have to acquire additional property rights to perfect our title to coal rights. If we fail to acquire additional property rights to perfect our title to coal rights, we may have to reduce our estimated reserves.

Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time, we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business and financial condition may be materially adversely affected.

We have obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in our being required to expense greater amounts than anticipated.

We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2020, the current and non-current portions of these obligations included:

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with Employer Retirement Income Security Act of 1974 (“ERISA”) regulations. The other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in workers’ compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense and our collateral requirements. Additionally, former miners and their family members asserting claims for pneumoconiosis benefits have generally been more successful asserting such claims in recent years as a result of the presumption within the PPACA of 2010 that a coal miner with 15 or more years of underground coal mining experience (or the equivalent) who develops a respiratory condition and meets the requirements for total disability under the Federal Act is presumed to be disabled due to coal dust exposure, thereby shifting the burden of proof from the employee to the employer/insurer to establish that this disability is not due to coal dust. The increasing success rate of such claims based upon the PPACA changed presumption and, as a result, the increasing expense incurred by us to insure against such claims could increase our expenses for long-term employee benefit obligations.

As a result of the Murray Energy bankruptcy, the Company may be asked to pay for certain liabilities previously held by Murray in a 2013 transaction between Murray and our former parent.

In 2013, Murray Energy and its subsidiaries (“Murray”) entered into a stock purchase agreement (the “Murray sale agreement”) with our former parent pursuant to which Murray acquired the stock of Consolidation Coal Company (“CCC”) and certain subsidiaries and certain other assets and liabilities. At the time of sale, the liabilities included certain retiree medical liabilities under the Coal Industry Retiree Health Benefits Act of 1992 (“Coal Act”) and certain federal black lung liabilities under the Black Lung Benefits Act (“BLBA”). Based upon information available to the Company, we estimate that the annual servicing costs of these liabilities are approximately $10 million to $20 million per year for the next ten years. The annual servicing cost would decline each year since the beneficiaries of the Coal Act consist principally of miners who retired prior to 1994.

Murray filed for Chapter 11 bankruptcy in October 2019. As part of the ongoing bankruptcy proceedings, Murray entered into a settlement with the United Mine Workers of America 1992 Benefit Plan (“1992 Plan”) to transfer retirees in the Murray Energy Section 9711 Plan into the 1992 Plan, which the bankruptcy court approved on April 30, 2020. The 1992 Plan recently filed an action in the United States District Court for the District of Columbia asking the court to make a determination whether the Company's former parent or the Company has any continuing retiree medical liabilities under the Coal Act. The Murray sale agreement includes indemnification by Murray with respect to the Coal Act and BLBA liabilities. In addition, the Company had agreed to indemnify its former parent relative to certain pre-separation liabilities. As of September 16, 2020, the Company has entered into a settlement agreement with Murray, and has withdrawn its claims in bankruptcy. The Company will continue to vigorously defend any claims that attempt to transfer any of such liabilities directly or indirectly to the Company, including raising all applicable defenses against the 1992 Plan's suit and those of any other party.

The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition, liquidity and results of operations.

As of December 31, 2020, our total long-term indebtedness was approximately $666 million, of which approximately $167 million was under our 11.00% senior secured notes due November 2025, $103 million was under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (“MEDCO”) 5.75% revenue bonds due September 2025, $66 million was under our Term Loan A Facility, $269 million was under our Term Loan B Facility, $56 million was associated with finance leases due through 2024, and $5 million was miscellaneous debt. At December 31, 2020, no borrowings were outstanding under our $400 million revolving credit facility or our $100 million accounts receivable securitization facility. The degree to which we are leveraged could have important consequences, including, but not limited to:

Our senior secured credit agreement and the indenture governing our 11.00% senior secured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indenture governing our 11.00% senior secured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis, including a maximum first lien gross leverage ratio, a maximum total net leverage ratio and a minimum fixed charge coverage ratio, as defined therein. Our senior secured credit agreement and the indenture governing our 11.00% senior secured notes impose a number of restrictions upon us, such as restrictions on us granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indenture governing our 11.00% senior secured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

Increases in interest rates or changes in the underlying base rate could adversely affect our business.

We have exposure to increases in interest rates. Based on our current variable debt level of $336 million as of December 31, 2020, primarily comprised of funds drawn on our Term Loan A and Term Loan B Facilities, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $3 million. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. In addition, our Term Loan A, Term Loan B, revolving credit and securitization facilities, as well as other short-term financing arrangements, utilize LIBOR as a basis for calculating interest. Those facilities allow for an alternative base rate in calculating interest. In the event that LIBOR would no longer be a published rate index, the allowable alternative base rate may increase our interest costs associated with those facilities.

Hedging transactions may limit our potential gains or cause us to lose money.

We enter into hedging arrangements in an effort to limit our exposure to interest rate volatility. These hedging arrangements may reduce, but will not eliminate, the potential effects of changing interest rates on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile interest rates, such transactions, depending on the hedging instrument used, may limit our potential gains if interest rates were to fall substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

However, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to interest rates. Furthermore, our price hedging strategy and future hedging transactions will be determined at the discretion of management. Our financial statements may reflect a gain or loss arising from an exposure to interest rates for which we are unable to enter into a completely effective hedge transaction.

Currently, our hedging arrangements partially mitigate our exposure to fluctuations in LIBOR interest rates through December 2022. In the event that LIBOR would no longer be a published rate index, we would have to modify, settle, or exchange the existing hedging arrangements. This could result in a loss of money and could adversely affect our results of operations, business and financial condition.

Terrorist attacks or cyber incidents could result in information theft, data corruption, operational disruption and/or financial loss.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber attacks than other targets in the United States. Deliberate attacks on our assets, or security breaches in our systems or infrastructure, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Similarly, our vendors or service providers could be the subject of such attacks or breaches that result in the risks of corruption or loss of our proprietary and sensitive data and/or the other disruptions as described above. In addition to the existing risks, the adoption of new technologies may also increase our exposure to data breaches or our ability to detect and remediate effects of a breach. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Certain provisions in our multi-year coal sales contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

Price adjustment, “price reopener” and other similar provisions in our multi-year coal sales contracts may reduce the protection from coal price volatility traditionally provided by coal supply contracts. Price reopener provisions are present in several of our multi-year coal sales contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our profitability.

Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal quality characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, ash fusion temperature and size consistency. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer. Our coal sales contracts also typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances or disobedience, strikes, railroad transportation delays caused by a force majeure event and actions or restraints by court order and governmental authority or arbitration award. 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 and some contracts may obligate us to perform notwithstanding what would typically be a force majeure event.

Our ability to operate our business effectively could be impaired if we fail to attract and retain qualified personnel, or if a meaningful segment of our employees become unionized.

Our ability to operate our business and implement our strategies depends, in part, on our continued ability to attract and retain the qualified personnel necessary to conduct our business. Efficient coal mining using modern techniques and equipment requires skilled employees in multiple disciplines such as electricians, equipment operators, mechanics, engineers and welders, among others. Although we have not historically encountered shortages for these types of skilled employees, competition in the future may increase for such positions, especially as it relates to needs of other industries with respect to these positions, including oil and gas. If we experience shortages of skilled employees in the future, our labor and overall productivity or costs could be materially adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employees. If our labor and contractor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially adversely affected.

Except for 36 of our employees at the CONSOL Marine Terminal who unionized in 2018, none of our employees are currently represented by a labor union or covered under a collective bargaining agreement, although many employers in our industry have employees who belong to a union. It is possible that employees at our other locations may join or seek recognition to form a labor union, or we may be required to become a labor agreement signatory. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations with our employees at the CONSOL Marine Terminal, we could potentially experience labor disputes, work stoppages or other disruptions in the business of the CONSOL Marine Terminal, which could negatively impact the profitability of the CONSOL Marine Terminal.

If we do not maintain effective internal controls over financial reporting, we could fail to accurately report our financial results.

During the course of the preparation of our financial statements, we evaluate our internal controls to identify and correct deficiencies in our internal controls over financial reporting. If we fail to maintain an effective system of disclosure controls or internal control over financial reporting, including satisfaction of the requirements of the Sarbanes-Oxley Act, we may not be able to accurately or timely report on our financial results or adequately identify and reduce fraud. As a result, the financial condition of our business could be adversely affected, current and potential future stockholders could lose confidence in us and/or our reported financial results, which may cause a negative effect on the trading price of our common stock, and we could be exposed to litigation or regulatory proceedings, which may be costly or divert management attention.

Risks Related to Our Common Stock and the Securities Market

Our stock price may fluctuate significantly.

The market price of our common stock may fluctuate significantly due to a number of factors, some of which may be beyond our control, including:

Stock markets in general have experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the trading price of our common stock. As a result of these factors, holders of our common stock may not be able to resell their shares at or above the market price at which they purchased their shares or may not be able to resell them at all. In addition, price volatility with our common stock may be greater if trading volume is low.

Furthermore, shares of our common stock are freely tradeable without restriction or further registration under the U.S. Securities Act of 1933, as amended (the “Securities Act”), unless the shares are owned by one of our “affiliates,” as that term is defined in Rule 405 under the Securities Act. As a result, a sale of a substantial amount of our common stock, or the perception that such a sale may take place, could cause our stock price to decline.

If securities analysts do not publish research or reports about our Company, or issue unfavorable commentary about us or downgrade our shares, the price of our shares could decline.

The trading market for our shares depends in part on the research and reports that third-party securities analysts publish about our Company and our industry. Because our ordinary shares were initially distributed to the public through the separation and distribution, there was not a marketing effort relating to the initial distribution of our shares of the type that would typically be part of an initial public offering of shares. We may be unable or slow to attract research coverage and if one or more analysts cease coverage of our Company, we could lose visibility in the market. The impact of the revised EU Markets in Financial Instruments Directive (“MiFID”), which requires that investment managers and investment advisors located in the EU “unbundle” research costs from commissions, may result in fewer securities analysts covering our Company. This is because investment firms subject to MiFID are no longer permitted to pay for research using client commissions or “soft dollars” and instead must pay such costs directly or through a research payment account funded by clients and governed by a budget that is agreed by the client, thereby raising their costs of providing research coverage. In addition, one or more analysts providing research coverage of our Company could use estimation or valuation methods that we do not agree with, downgrade our shares or issue other negative commentary about our company or our industry. As a result of one or more of these factors, the trading price of our shares could decline.

We cannot guarantee the timing, amount, or payment of dividends on our common stock in the future.

The payment and amount of any future dividend will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition and prospects, our capital requirements and access to capital markets, covenants associated with certain of our debt obligations, legal requirements and other factors that our board of directors may deem relevant, and there can be no assurance that we will pay a dividend in the future.

Your percentage of ownership in us may be diluted in the future.

Your percentage of ownership in us may be diluted because of equity issuances for acquisitions, capital market transactions or otherwise, including, without limitation, equity awards that we may be granting to our directors, officers and employees. Such issuances may have a dilutive effect on our earnings per share, which could adversely affect the market price of our common stock.

It is anticipated that the compensation committee of the board of directors of the Company will grant additional equity awards to Company employees and directors, from time to time, under the Company’s compensation and employee benefit plans. These additional awards will have a dilutive effect on the Company’s earnings per share, which could adversely affect the market price of the Company’s common stock.

In addition, our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock with respect to dividends and distributions, as our board of directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant the holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.

There can be no assurance that we will continue to repurchase shares of our common stock or outstanding debt securities.

In December 2017, CONSOL Energy's Board of Directors approved a program to repurchase, from time to time, the Company's outstanding shares of common stock or its 11.00% Senior Secured Second Lien Notes due 2025, in an aggregate amount of up to $50 million through the period ending June 30, 2019. The program was subsequently amended by CONSOL Energy's Board of Directors on four separate occasions, the most recent of which occurred in May 2020. As a result of such amendments, CONSOL may now repurchase up to $270 million of the Company's common stock or its 11.00% Senior Secured Second Lien Notes due 2025 through the period ending June 30, 2022, subject to certain limitations in the Company's credit agreement and the tax matters agreement. Our share repurchase program does not obligate us to repurchase any specific number of debt securities or common shares and may be suspended from time to time or terminated at any time prior to its expiration. There can be no assurance that we will repurchase shares or debt securities under the repurchase program in the future in any particular amounts or at all. A reduction in, or elimination of, share repurchases could have a negative effect on our share price.

Certain provisions of our amended and restated certificate of incorporation and amended and restated bylaws, and of Delaware law, may prevent or delay an acquisition of us, which could decrease the trading price of our common stock.

The Company’s amended and restated certificate of incorporation and amended and restated by-laws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the bidder and to encourage prospective acquirers to negotiate with the Company’s board of directors rather than to attempt a hostile takeover. These provisions include, among others:

In addition, we are subject to Section 203 of the Delaware General Corporation Law (“DGCL”). Section 203 provides that, subject to limited exceptions, persons that (without prior board approval) acquire, or are affiliated with a person that acquires, more than 15% of the outstanding voting stock of a Delaware corporation shall not engage in any business combination with that corporation, including by merger, consolidation or acquisitions of additional shares, for a three-year period following the date on which that person or its affiliate becomes the holder of more than 15% of the corporation’s outstanding voting stock.

We believe these provisions will protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions could have the effect of delaying, deferring or preventing a change in control or the removal of the existing board of directors and/or management, of deterring potential acquirers from making an offer to our stockholders and of limiting any opportunity to realize premiums over prevailing market prices for our common stock in connection therewith. This could be the case notwithstanding that a majority of our stockholders might benefit from such a change in control or offer.

In addition, an acquisition or further issuance of the Company’s stock could trigger the application of Section 355(e) of the Code, causing the distribution to be taxable to our former parent. Under the tax matters agreement, the Company would be required to indemnify our former parent for the resulting tax, and this indemnity obligation might discourage, delay or prevent a change of control that could be considered favorable.

Our certificate of incorporation designates the State Courts of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain an alternative judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, a state court sitting in the State of Delaware (or, if no state court located within the State of Delaware has jurisdiction, the federal court for the District of Delaware) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

Any person or entity purchasing or otherwise holding any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

None.

See “Detail Coal Operations” in Item 1 of this Annual Report on Form 10-K for a description of our mining properties, incorporated herein by this reference. In addition to our mining properties referenced in the prior sentence, through our CONSOL Marine Terminal located in the Port of Baltimore, we provide coal and export terminal services. Our principal executive offices are located at 1000 CONSOL Energy Drive, Suite 100, Canonsburg, Pennsylvania 15317-6506. See the map under “Our Company” in Item 1 of this Annual Report on Form 10-K for the location of the Company's material properties.

Our operations are subject to a variety of risks and disputes normally incidental to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation. Refer to Note 22, “Commitments and Contingent Liabilities,” in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K, incorporated herein by this reference.

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual report.

PART II

Shares of the Company's common stock are listed on the New York Stock Exchange and trade under the symbol “CEIX”. Trading of the Company's common stock began as “when-issued” trading on November 3, 2017 and began as “regular-way” trading on November 29, 2017.

As of February 1, 2021, there were 89 holders of record of our common stock.

The following performance graph compares CONSOL Energy's cumulative total shareholder return to that of the Company's peer group and the Standard & Poor's 500 Stock Index. The peer group, for the purposes of the information presented below, is comprised of Alliance Resource Partners LP, Arch Resources, Inc. (formerly known as Arch Coal Inc.), Contura Energy, Inc., Cloud Peak Energy, Inc., Foresight Energy LP, Hallador Energy Company, Peabody Energy Corporation, Ramaco Resources, Inc., Warrior Met Coal, Inc. and Westmoreland Coal Company. 

The graph above tracks the performance of an initial investment of $100 in CONSOL Energy's common stock and each member of the peer group and the Standard & Poor's 500 Stock Index, including the reinvestment of any dividends, from November 3, 2017 (beginning of “when-issued” trading) through December 31, 2020.

The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).

Repurchases of Equity Securities

There were no repurchases of the Company's equity securities during the three months ended December 31, 2020. Since the December 2017 inception of the Company's current stock, unit and debt repurchase program, CONSOL Energy Inc.'s Board of Directors subsequently amended the program on four separate occasions. As a result of such amendments, the Company may now repurchase up to $270 million of the Company's stock and debt until June 30, 2022. As of February 12, 2021, approximately $91.4 million remained available under the stock, unit and debt repurchase program. The program does not obligate CONSOL Energy to acquire any particular amount of its common stock or notes, and can be modified or suspended at any time at the Company's discretion. See Note 5 - Stock, Unit and Debt Repurchases of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Dividends

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy's Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CONSOL Energy's financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. The Company's Senior Secured Credit Facilities limit CONSOL Energy's ability to pay dividends up to $25 million annually, which increases to $50 million annually when the Company's total net leverage ratio is less than 1.50 to 1.00 and subject to an aggregate amount up to a cumulative credit calculation set forth in the facilities, with additional conditions of no outstanding borrowings and no more than $200 million of outstanding letters of credit on the Revolving Credit Facility, and the total net leverage ratio shall not be greater than 2.00 to 1.00. The total net leverage ratio was 2.54 to 1.00 and the cumulative credit was approximately $16 million at December 31, 2020. The cumulative credit starts with $50 million and builds with excess cash flow commencing in 2018. The Senior Secured Credit Facilities do not permit dividend payments in the event of default. The Indenture to the 11.00% Senior Secured Second Lien Notes limits dividends when the Company's total net leverage ratio exceeds 2.00 to 1.00 and subject to an amount not to exceed an annual rate of 4.0% of the quoted public market value per share of such common stock at the time of the declaration. The Indenture does not permit dividend payments in the event of default.

See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to CONSOL Energy's equity compensation plans.

Merger with CONSOL Coal Resources LP

On December 30, 2020, we completed the acquisition of all of the outstanding common units of CONSOL Coal Resources, and CONSOL Coal Resources became our indirect wholly-owned subsidiary (see Note 2 - Major Transactions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). In connection with the closing of the CCR Merger, we issued approximately 8.0 million shares of our common stock to acquire the approximately 10.9 million common units of CCR held by third-party CCR investors at a fixed exchange ratio of 0.73 shares of CEIX common stock for each CCR unit, for total implied consideration of $51.7 million.

COVID-19 Update

 The Company is monitoring the impact of the COVID-19 pandemic (“COVID-19”) and has taken, and will continue to take, steps to mitigate the potential risks and impact on the Company and its employees. The health and safety of our employees is paramount. In response to two employees testing positive for COVID-19, the Company temporarily curtailed production at the Bailey Mine for two weeks at the end of March. To date, the Company has experienced a few localized outbreaks, but due to the health and safety procedures put in place by the Company, we have been able to continue operating without production curtailment. The Company continues to monitor the health and safety of its employees closely in order to limit potential risks to our employees, contractors, family members and the community.

We are considered a critical infrastructure company by the U.S. Department of Homeland Security. As a result, we were exempt from Pennsylvania Governor Tom Wolf's executive order, issued in March 2020, closing all businesses that are not life sustaining until Pennsylvania's phased reopening, which began in the second quarter of 2020. The unprecedented decline in coal demand that began in the first quarter hit its lowest point in May 2020, and has improved through the fourth quarter. In response to the decline in demand for our coal as a result of COVID-19, we idled four of our five longwalls for periods of time beginning in the second quarter. As demand improved, we restarted longwalls and ultimately ran four of the five longwalls for the majority of the third quarter and for the entire fourth quarter. This decline in coal demand has negatively impacted our operational, sales and financial performances year-to-date and we expect that this negative impact will continue as the pandemic continues. However, we saw steady improvement in the demand for our coal throughout the third and fourth quarters of 2020.

While some government-imposed shut-downs of non-essential businesses in the United States and abroad have been phased out, there is a possibility that such shut-downs may be reinstated after being lifted as COVID-19 continues to spread rapidly. We expect that depressed domestic and international demand for our coal will continue for so long as there are widespread, government-imposed shut-downs of business activity. Depressed demand for our coal may also result from a general recession or reduction in overall business activity caused by COVID-19. Additionally, some of our customers have already attempted, and may in the future attempt, to invoke force majeure or similar provisions in the contracts they have in place with us in order to avoid taking possession of and paying us for our coal that they are contractually obligated to purchase. Sustained decrease in demand for our coal and the failure of our customers to purchase coal from us that they are obligated to purchase pursuant to existing contracts would have a material adverse effect on our results of operations and financial condition. The extent to which COVID-19 may adversely impact our business depends on future developments, which are highly uncertain and unpredictable, including new information concerning the severity of the outbreak, the pace and effectiveness of vaccination efforts and the effectiveness of actions globally to contain or mitigate its effects. We expect this will continue to negatively impact our results of operations, cash flows and financial condition. The Company will continue to take steps it believes are appropriate to mitigate the impacts of COVID-19 on its operations, liquidity and financial condition.

2020 Highlights:

Outlook for 2021:

How We Evaluate Our Operations

Our management team uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability. The metrics include: (i) coal production, sales volumes and average revenue per ton; (ii) cost of coal sold, a non-GAAP financial measure; (iii) cash cost of coal sold, a non-GAAP financial measure; (iv) average margin per ton sold, an operating ratio derived from non-GAAP financial measures; and (v) average cash margin per ton sold, an operating ratio derived from non-GAAP financial measures.

Cost of coal sold, cash cost of coal sold, average margin per ton sold and average cash margin per ton sold normalize the volatility contained within comparable GAAP measures by adjusting certain non-operating or non-cash transactions. Each of these non-GAAP metrics are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

These non-GAAP financial measures should not be considered an alternative to total costs, net income, operating cash flow, or any other measure of financial performance or liquidity presented in accordance with GAAP. These measures exclude some, but not all, items that affect measures presented in accordance with GAAP,  and these measures and the way we calculate them may vary from those of other companies. As a result, the items presented below may not be comparable to similarly titled measures of other companies.

Reconciliation of Non-GAAP Financial Measures

We evaluate our cost of coal sold and cash cost of coal sold on an aggregate basis. We define cost of coal sold as operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The cost of coal sold includes items such as direct operating costs, royalty and production taxes, direct administration costs, and depreciation, depletion and amortization costs on production assets. Our costs exclude any indirect costs, such as selling, general and administrative costs, freight expenses, interest expenses, depreciation, depletion and amortization costs on non-production assets and other costs not directly attributable to the production of coal. The cash cost of coal sold includes cost of coal sold less depreciation, depletion and amortization costs on production assets. The GAAP measure most directly comparable to cost of coal sold and cash cost of coal sold is total costs and expenses. 

The following table presents a reconciliation of cost of coal sold and cash cost of coal sold to total costs and expenses, the most directly comparable GAAP financial measure, on a historical basis, for each of the periods indicated (in thousands).

We define average margin per ton sold as average revenue per ton sold, net of average cost of coal sold per ton. We define average cash margin per ton sold as average revenue per ton sold, net of average cash cost of coal sold per ton. The GAAP measure most directly comparable to average margin per ton sold and average cash margin per ton sold is total coal revenue.

The following table presents a reconciliation of average margin per ton sold and average cash margin per ton sold to total coal revenue, the most directly comparable GAAP financial measure, on a historical basis, for each of the periods indicated (in thousands, except per ton information).

We define adjusted EBITDA as (i) net income (loss) plus income taxes, net interest expense and depreciation, depletion and amortization, as adjusted for (ii) certain non-cash items, such as long-term incentive awards. The GAAP measure most directly comparable to adjusted EBITDA is net income (loss).

Results of Operations: Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019 

Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders

CONSOL Energy reported net loss attributable to CONSOL Energy Inc. shareholders of $10 million for the year ended December 31, 2020, compared to net income attributable to CONSOL Energy Inc. shareholders of $76 million for the year ended December 31, 2019.

CONSOL Energy consists of the Pennsylvania Mining Complex and the CONSOL Marine Terminal, as well as various corporate and other business activities that are not allocated to the PAMC or the CONSOL Marine Terminal. The other business activities include the development of the Itmann Mine, the Greenfield Reserves, closed and idle mine activities, selling, general and administrative activities, interest expense and income taxes, as well as various other non-operated activities.

PAMC ANALYSIS:

The PAMC division's principal activities consist of mining, preparation and marketing of thermal coal. The division also includes selling, general and administrative costs, as well as various other activities assigned to the PAMC division, but not included in the cost components on a per unit basis.

The PAMC division had earnings before income tax of $17 million for the year ended December 31, 2020, compared to earnings before income tax of $197 million for the year ended December 31, 2019. Variances are discussed below.

Coal Production

The table below presents total tons produced (in thousands) from the Pennsylvania Mining Complex for the periods indicated:

Coal production was 18.8 million tons for the year ended December 31, 2020, compared to 27.3 million tons for the year ended December 31, 2019. The PAMC division's coal production decreased primarily due to the temporary idling of longwalls at the Bailey and Enlow Fork mines. This was mainly in response to weakened customer demand as a result of a warmer than normal winter, followed by global demand destruction due to the COVID-19 pandemic and, in response, the widespread government-imposed shut-downs, which significantly reduced electricity consumption and, therefore, demand for the Company's coal.

Coal Operations

The PAMC division's coal revenue and cost components on a per unit basis for these periods were as follows:

(1) Average cash cost of coal sold per ton and average cost of coal sold per ton are non-GAAP measures, and average margin per ton sold and average cash margin per ton sold are operating ratios derived from non-GAAP measures. See “How We Evaluate Our Operations - Reconciliation of Non-GAAP Financial Measures” for a reconciliation of non-GAAP measures to the most directly comparable GAAP measures.

Coal Revenue

Coal revenue was $771 million for the year ended December 31, 2020, compared to $1,289 million for the year ended December 31, 2019. Total tons sold decreased in the period-to-period comparison in response to weakened customer demand due to a warmer than normal winter followed by the COVID-19 pandemic, each of which reduced electricity consumption and, therefore, demand for the Company's coal. Additionally, lower natural gas prices as compared to the prior year contributed to electric generation trending toward gas, rather than coal, as a fuel source. The decrease in overall demand, including in both the domestic and export markets the Company serves, resulted in lower pricing received on the Company's sales contracts.

Freight Revenue and Freight Expense

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company contractually provides transportation services. Freight revenue is completely offset by freight expense. Freight revenue and freight expense were both $40 million for the year ended December 31, 2020, compared to $20 million for the year ended December 31, 2019. The $20 million increase was due to increased shipments to customers where the Company was contractually obligated to provide transportation services.

Miscellaneous Other Income

Miscellaneous other income was $84 million for the year ended December 31, 2020, compared to $23 million for the year ended December 31, 2019. The $61 million increase was primarily the result of the sale of certain mining rights and additional customer contract buyouts in the year ended December 31, 2020, offset, in part, by a decrease in sales of externally purchased coal to blend and resell. These partial contract buyouts involved negotiations to reduce coal quantities of several customer contracts in exchange for payment of certain fees to the Company, and do not impact forward contract terms.

Cost of Coal Sold

Cost of coal sold is comprised of operating costs related to produced tons sold, along with changes in both the volumes and carrying values of coal inventory. The costs of coal sold include items such as direct operating costs, royalties and production taxes, direct administration costs and depreciation, depletion, and amortization costs on production assets. Total cost of coal sold was $714 million for the year ended December 31, 2020, or $307 million lower than the $1,021 million for the year ended December 31, 2019. Average cost of coal sold per ton was $38.24 for the year ended December 31, 2020, compared to $37.37 for the year ended December 31, 2019. The decrease in the total cost of coal sold was primarily driven by decreased production activity during the year ended December 31, 2020, mainly in response to weakened market demand, while on a per unit basis, the decreased production resulted in an overall increase in the average cost of coal sold per ton.

Other Costs

Other costs include items that are assigned to the PAMC division but are not included in unit costs, such as idle mine costs, coal reserve holding costs and purchased coal costs. Total other costs increased $40 million in the year ended December 31, 2020 compared to the year ended December 31, 2019. The increase was primarily attributable to the temporary idling of longwalls at the Bailey and Enlow Fork mines due to the COVID-19 pandemic and, in response, the widespread government-imposed shutdowns, which significantly reduced electricity consumption and industrial activity and, therefore, demand for the Company's coal.

Selling, General and Administrative Costs

The amount of selling, general and administrative costs related to the PAMC division was $53 million for the year ended December 31, 2020, compared to $63 million for the year ended December 31, 2019. The $10 million decrease in the period-to-period comparison was primarily related to several initiatives launched by management to reduce costs, including compensation reductions, curtailment of discretionary expenses and headcount management, partially offset by fees incurred as a result of the CCR Merger.

CONSOL MARINE TERMINAL ANALYSIS: 

The CONSOL Marine Terminal division provides coal export terminal services through the Port of Baltimore. The division also includes selling, general and administrative activities and interest expense, as well as various other activities assigned to the CONSOL Marine Terminal division.

The CONSOL Marine Terminal division had earnings before income tax of $33 million for the year ended December 31, 2020, compared to earnings before income tax of $34 million for the year ended December 31, 2019. 

          Overall earnings before income tax were consistent in the period-to-period comparison. The improvement in operating and other costs was the result of cost reduction initiatives implemented at the CONSOL Marine Terminal, and was also directly related to reduced throughput due to weakened export markets and global demand destruction as a result of the COVID-19 pandemic and, in response, the widespread government-imposed shut-downs. However, due to the take-or-pay arrangements in both the years ended December 31, 2020 and 2019, the decline in demand was mitigated. This improvement was offset by an increase in selling, general, and administrative costs, which are allocated to the Company's divisions based on a percentage of resources utilized, a percentage of total revenue and a percentage of total projected capital expenditures.

OTHER ANALYSIS:

The other division includes revenue and expenses from various corporate and diversified business activities that are not allocated to the PAMC or the CONSOL Marine Terminal divisions. The diversified business activities include the development of the Itmann Mine, the Greenfield Reserves, closed mine activities, selling, general and administrative activities, interest expense and income taxes, as well as various other non-operated activities.

Other business activities had a loss before income tax of $59 million for the year ended December 31, 2020, compared to a loss before income tax of $133 million for the year ended December 31, 2019. Variances are discussed below.