CONSOL Energy 10K 2023 Annual report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______to _______

Commission file number: 001-38147

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)


Delaware			82-1954058
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

275 Technology Drive Suite 101

Canonsburg, PA 15317-9565

(724) 416-8300

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock ($0.01 par value)	CEIX	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☒ No ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate value of common stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $2,165,152,746 as of June 30, 2023, the last business day of the registrant's

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most recently completed second fiscal quarter, based on the reported closing price of the common stock as reported on The New York Stock Exchange on such date.

The number of shares outstanding of the registrant's common stock as of January 31, 2024 was 29,603,460 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CONSOL Energy Inc.'s Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed within 120 days of the end of the registrant's fiscal year are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.

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		Page
PART I
ITEM 1.	Business	6
ITEM 1A.	Risk Factors	31
ITEM 1B.	Unresolved Staff Comments	52
ITEM 1C.	Cybersecurity	52
ITEM 2.	Properties	53
ITEM 3.	Legal Proceedings	53
ITEM 4.	Mine Safety Disclosures	53

PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
ITEM 8.	Financial Statements and Supplementary Data	73
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	119
ITEM 9A.	Controls and Procedures	119
ITEM 9B.	Other Information	121
ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	121

PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	121
ITEM 11.	Executive Compensation	121
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	121
ITEM 13.	Certain Relationships and Related Transactions and Director Independence	121
ITEM 14.	Principal Accountant Fees and Services	121

PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	122
SIGNATURES		129

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PART I

Important Definitions Referenced in this Annual Report

•“CONSOL Energy,” “we,” “our,” “us,” “our Company” and “the Company” refer to CONSOL Energy Inc. and its subsidiaries;

•“Btu” means one British thermal unit;

•“CCR Merger” refers to the merger under that certain Agreement and Plan of Merger, dated as of October 22, 2020, among the Company, Transformer LP Holdings Inc., a wholly-owned subsidiary of the Company (“Holdings”), Transformer Merger Sub LLC, a wholly-owned subsidiary of Holdings (“Merger Sub”), the Partnership and the General Partner, pursuant to which Merger Sub merged with and into the Partnership, with the Partnership surviving as an indirect, wholly-owned subsidiary of the Company, which merger closed on December 30, 2020;

•“coal reserves” refer to the Company's proven and probable coal reserves as defined by Section 1300 et. seq. of Regulation S-K that could be economically mineable, after taking into account modifying factors, including mining recovery and preparation plant yield;

•“CONSOL Marine Terminal” refers to the Company's terminal operations located at the Port of Baltimore, Maryland;

•“former parent” refers to CNX Resources Corporation and its consolidated subsidiaries;

•“General Partner” refers to PA Mining Complex GP LLC (formerly known as CONSOL Coal Resources GP LLC), a Delaware limited liability company and the general partner of the Partnership;

•“Greenfield Reserves and Resources” means those undeveloped reserves and resources owned by the Company in the Northern Appalachian, Central Appalachian and Illinois basins that are not associated with the Pennsylvania Mining Complex or the Itmann Mining Complex;

•“Itmann Mining Complex” refers to the Company's Itmann No. 5 metallurgical coal mine and coal preparation plant located in Wyoming County, West Virginia, and surrounding reserves to be processed and sold through the Itmann Mining Complex coal preparation plant;

•“mmBtu” means one million British thermal units;

•“Partnership” refers to PA Mining Complex LP (formerly known as CONSOL Coal Resources LP), a Delaware limited partnership that is a wholly-owned subsidiary of the Company and holds an undivided interest in, and is the sole operator of, the Pennsylvania Mining Complex; and

•“Pennsylvania Mining Complex” or “PAMC” refers to the Bailey, Enlow Fork and Harvey coal mines, the Central Preparation Plant, and related coal reserves, assets and operations located in southwestern Pennsylvania and northern West Virginia.

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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,” “would,” 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:

•deterioration in economic conditions (including continued inflation) or changes in consumption patterns of our customers may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•volatility and wide fluctuation in coal prices based upon a number of factors beyond our control;

•the effects pandemics may have on our business and results of operations and on the global economy;

•an extended decline in the prices we receive for our coal affecting our operating results and cash flows;

•significant downtime of our equipment or inability to obtain equipment, parts or raw materials;

•decreases in the availability of, or increases in the price of, commodities or capital equipment used in our coal mining operations;

•our reliance on major customers, our ability to collect payment from our customers and uncertainty in connection with our customer contracts;

•our inability to acquire additional coal reserves or resources that are economically recoverable;

•the availability and reliability of transportation facilities and other systems that deliver our coal to market and fluctuations in transportation costs;

•a loss of our competitive position;

•foreign currency fluctuations that could adversely affect the competitiveness of our coal abroad;

•the risks related to the fact that a significant portion of our production is sold in international markets and our compliance with export control and anti-corruption laws;

•coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;

•the impact of current and future regulations to address climate change, the discharge, disposal and clean-up of hazardous substances and wastes and employee health and safety on our operating costs as well as on the market for coal;

•the risks inherent in coal operations, including being subject to unexpected disruptions caused by adverse geological conditions, equipment failure, delays in moving out longwall equipment, railroad derailments, security breaches or terroristic acts and other hazards, delays in the completion of significant construction or repair of equipment, fires, explosions, seismic activities, accidents and weather conditions;

•the risks associated with operating primarily in a single geographic area;

•failure to obtain or renew surety bonds or insurance coverages on acceptable terms;

•the effects of coordinating our operations with oil and natural gas drillers and distributors operating on our land;

•our inability to obtain financing for capital expenditures on satisfactory terms;

•the effect of new or existing laws or regulations or tariffs and other trade measures;

•our inability to find suitable acquisition targets or integrating the operations of future acquisitions into our operations;

•obtaining, maintaining and renewing governmental permits and approvals for our coal operations;

•the effects of asset retirement obligations, employee-related long-term liabilities and certain other liabilities;

•the effects of global conflicts on commodity prices and supply chains;

•uncertainties in estimating our economically recoverable coal reserves;

•the outcomes of various legal proceedings, including those which are more fully described herein;

•defects in our chain of title for our undeveloped reserves or failure to acquire additional property to perfect our title to coal rights;

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•the risk of our debt agreements, our debt and changes in interest rates affecting our operating results and cash flows;

•information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;

•the potential failure to retain and attract qualified personnel of the Company;

•failure to maintain effective internal controls over financial reporting;

•the effects of our securities being excluded from certain investment funds as a result of increased environmental, social and corporate governance (“ESG”) practices;

•uncertainty with respect to the Company’s common stock, potential stock price volatility and future dilution;

•uncertainty regarding the timing and value of any dividends we may declare;

•uncertainty as to whether we will repurchase shares of our common stock or outstanding debt securities;

•inability of stockholders to bring legal action against us in any forum other than the state courts of Delaware; and

•other unforeseen factors.

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.

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ITEM 1. Business

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.

The address of our principal executive offices is 275 Technology Drive Suite 101, 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 share amounts, and unless otherwise indicated.

Our Company

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

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

We are continuing to expand our presence in the metallurgical coal market through our Itmann Mining Complex in West Virginia. The Itmann Preparation Plant was constructed in 2022, began processing coal in late September 2022 and shipped its first train in October 2022. The plant includes a train loadout located on the Guyandotte Class I rail line, which can be served by both Norfolk Southern and CSX.

Our operations, including the PAMC and the CONSOL Marine Terminal, have consistently generated strong free cash flows. As of December 31, 2023, the PAMC controls 583.5 million tons of high-quality Pittsburgh seam reserves, enough to allow for an equivalent of more than 20 years of full-capacity production. As of December 31, 2023, the Itmann Mining Complex includes 28.4 million tons of recoverable coal reserves that are sufficient to support an equivalent of more than 30 years of full-capacity production, based on our current estimates. In addition, we own or control approximately 1.3 billion tons of Greenfield Reserves and Resources located in the Northern Appalachian Basin (“NAPP”), the Central Appalachian Basin (“CAPP”) and the Illinois Basin (“ILB”). Our vision is to maximize cash flow generation through the safe, compliant and efficient operation of this core asset base, while maintaining a strong balance sheet and liquidity, returning capital through share buybacks and/or dividends, and, when prudent, allocating capital toward compelling growth and diversification opportunities.

Our core businesses consist of our:

•Pennsylvania Mining Complex: The PAMC, which includes the Bailey Mine, the Enlow Fork Mine, the Harvey Mine and the Central Preparation Plant, has extensive high-quality coal reserves. 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 mining operations. The design of the PAMC is optimized to produce large quantities of coal on a cost-efficient basis. We can sustain high production volumes at comparatively low operating costs due to, among other things, our technologically advanced longwall mining systems, logistics infrastructure and safety. All our mines at the PAMC 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.

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•CONSOL Marine Terminal: Through our subsidiary CONSOL Marine Terminals LLC, we provide coal export terminal services through the Port of Baltimore. 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 and CSX.

•Itmann Mining Complex: Construction of the Itmann No. 5 Mine, located in Wyoming County, West Virginia, began in the second half of 2019; development mining began in April 2020, but the pace of the project was intentionally slowed to minimize capital spending due to the uncertainties surrounding the COVID-19 pandemic. The coal preparation plant was commissioned during the third quarter of 2022 and shipped its first train in October 2022. The operation continued to ramp up in 2023 with a focus on mains development and staffing needed for the long-term viability of the mine. The Company anticipates approximately 900 thousand tons per year of high-quality, low-vol coking coal production from the Itmann No. 5 Mine once it achieves its full run rate, with an anticipated mine life of 30+ years. The preparation plant also includes a rail loadout and the capability for processing up to an additional 750 thousand to 1 million saleable tons annually from third-parties and mining of our surrounding reserves. This additional processing revenue is expected to provide an avenue of growth for the Company.

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 feed stock for steel and other industrial applications as well as electric generation while profitably growing through innovative technology and perseverance. Our core values of safety, compliance, and continuous improvement are the foundation of the Company’s identity and are the basis for how management defines continued success. We believe the Company’s rich resource base, coupled with these core values, will allow management to create value for the long-term. We believe that the use of coal in industrial applications, including but not limited to the steel-making process, and as a fuel source for electricity will continue for many years. Furthermore, our Itmann Mining Complex is specifically suited to benefit from the demand related to global infrastructure needs.

Our Strategy

The Company remains focused on increasing stockholder value by safely and compliantly operating our business, growing our metallurgical coal business, and, over time, diversifying into other business opportunities. The Company’s existing coal assets align with these objectives. Our current production from the Bailey, Enlow Fork and Harvey mines can be sold domestically or abroad into the industrial, metallurgical or power generation coal markets. These low-cost mines, with up to five operating longwalls, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals as well as several Illinois Basin 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 wholly-owned CONSOL Marine Terminal, which is served by both Norfolk Southern and CSX, will allow us to continue to participate

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competitively in the global industrial, metallurgical and power generation 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 production from our Itmann No. 5 Mine, which produces high quality low-vol metallurgical coal primarily used in steel making applications, and are starting to explore and invest in some innovative and more sustainable uses for coal, including through joint ventures and other opportunities. 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 the power generation coal markets.

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

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

We plan to judiciously direct the cash generated by our operations toward those opportunities that present the greatest potential for value creation to our stockholders, particularly those that take advantage of synergies with our asset base and/or 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 that complement our operations. The PAMC, the Itmann Mining Complex and our Greenfield Reserves and Resources present the potential for organic growth projects if long-term market conditions are favorable. For example, we are actively engaged in continuous improvement or research and development projects to improve the productivity of our Central Preparation Plant and our mining operations through the use of technology, automation, data visualization and analytics.

We regularly evaluate our Greenfield Reserves and Resources to identify organic growth opportunities that we believe can add value to our business. As such, we announced the commencement of our Itmann No. 5 Mine project in May 2019, began development mining in April 2020, and commissioned a coal preparation plant and began operations during the third quarter of 2022. The Itmann No. 5 Mine adds a new metallurgical coal product stream to our mix of products. Our Greenfield Reserves and Resources associated with certain NAPP and CAPP properties provide additional potential organic growth opportunities in the metallurgical coal space, and our Greenfield Resources associated with the Mason Dixon and River Mine projects present potential organic growth opportunities or monetization opportunities to create value. Our management team has extensive experience in developing, operating and marketing a wide variety of coal assets and, we believe, is well qualified to evaluate organic and external growth opportunities. We plan to carefully weigh any capital investment decisions against alternate uses of the cash to help ensure we are delivering the most value to our stockholders.

We are also pursuing a variety of alternative and innovative uses of coal to diversify our business. These activities are led by CONSOL Innovations LLC, our wholly-owned subsidiary located in Triadelphia, WV, which is focused on creating long-term growth and diversification opportunities through sustainable innovations in the carbon products and materials markets. For example, in 2022, we acquired the remaining equity stake in CFOAM Corp. (“CFOAM”), which manufactures high-performance carbon foam products from coal that can be used in the aerospace, military, industrial and commercial product markets. In 2023, we acquired the assets of Touchstone Advanced Composites (“TAC”), an innovative composite tooling supplier for the aerospace industry that uses our CFOAM product. Also in 2023, we expanded our research and development activities that are focused on using coal and coal mining/preparation plant waste streams for battery applications, including the development of battery electrode materials.

We continue to partner with Ohio University, the U.S. Department of Energy and certain other industry partners on several projects to develop coal-derived materials that can potentially be used in applications such as engineered composite building materials and three-dimensional printing. Another initiative, our 21st Century Power Plant project, is also receiving funding from the Department of Energy to evaluate a next-generation power plant 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, our Department of Energy-sponsored REMEDY project seeks to develop an efficient, safe and cost-effective technology for mitigation of mine ventilation air methane that, if successful, could have broader market applicability.

From time to time, we also evaluate investments in industries and sectors that are not related to coal but may provide long-term business opportunities that develop due to the potential energy transition efforts of various local, federal and international governments.

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Opportunistically grow our presence in the industrial and metallurgical markets, while preserving coal sales to top-performing rail-served power plants in our core market areas

We plan to minimize our market risk and maximize realizations by continuing to focus on placing a growing portion of our production in the export markets, where we sell to industrial, metallurgical and power generation end-users. This approach provides us pricing upside when markets are strong and with volume stability when markets are weak. Of our 2023 sales tons, approximately 61% were sold to export markets and 39% were sold to domestic customers. Of our 2023 sales tons, 49% were sold in the electric power generation market, 39% were sold in the industrial market and 12% were sold in the metallurgical market. Comparatively, of our 2017 sales tons, approximately 32% were sold to export markets and 68% were sold to domestic customers. Of our 2017 sales tons, 82% were sold in the electric power generation market, 10% were sold in the industrial market and 8% were sold in the metallurgical market. Historically, the majority of our production was directed toward our established base of domestic power plant customers, many of which were secured through spot, annual or multi-year contracts.

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 PAMC Mine Safety and Health Administration (“MSHA”) total reportable incident rate was approximately 57% lower than the national average underground bituminous coal mine incident rate. Furthermore, our PAMC MSHA significant and substantial (“S&S”) citation rate per 100 inspection hours was approximately 88% lower than the industry’s average MSHA S&S citation rate over the twelve-month period ended December 31, 2023. 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 7.40 tons per employee hour since 2015. We intend to continue to grow the economic competitiveness of our operations by proactively identifying, pursuing and implementing efficiency improvements and new technologies that can drive down unit costs without compromising safety or compliance.

Maintain Ability to Access Capital Markets

We have generated significant cash from operations since becoming a publicly-traded company, which has allowed us to opportunistically refinance and pay down our debt. The reduced indebtedness on our balance sheet and improved liquidity allow us to pursue attractive organic growth opportunities and 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. In connection with this, we filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission (“SEC”) in February 2022 that allows us to issue an indeterminate amount of securities, including common stock, preferred stock, debt securities and warrants. This shelf registration statement is intended to provide us with increased financial flexibility and more efficient access to the capital markets.

Furthermore, we successfully accessed the municipal bond market in 2021 and borrowed the proceeds received from the sale of tax-exempt bonds issued by the Pennsylvania Economic Development Financing Authority in an aggregate principal amount of $75 million. In 2022, we amended and extended our revolving credit facility and accounts receivable securitization facility. In 2023, we again amended our revolving credit facility, which increased the available revolving commitments from $260 million to $355 million and provides for the Company's ability to increase the revolving commitments or issue term loans in an additional amount not to exceed $45 million and up to an aggregate total amount of $400 million. The secured incremental commitments of $95 million include commitments from multiple new lenders to the facility and upsized commitments from 60% of existing lenders.

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.

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Furthermore, our ability to enter into multi-year contracts with our longstanding customer base, as well as strategic industrial export customers, 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, 2023, the PAMC included 583.5 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 12,972 Btu/lb, while production from the PRB, ILB, CAPP and the rest of NAPP averages approximately 8,700 Btu/lb, 11,200 Btu/lb, 12,000 Btu/lb and 12,400 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, 2023). Moreover, our remaining reserves have an average sulfur content of 2.32%, while production from the ILB averages 2.95% sulfur and production from the rest of NAPP averages 3.32% sulfur (again, based on EIA power plant delivery data for the three years ended June 30, 2023). With our high Btu content and low-cost structure, our 2023 PAMC average cost of coal sold per ton was $1.67 on an mmBtu basis, which 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 Mining Complex includes 28.4 million tons of recoverable coal reserves that are sufficient to support more than 30 years of full-capacity production, and our 1.3 billion tons of Greenfield Reserves and Resources in NAPP, CAPP and ILB feature both thermal and metallurgical reserves and resources and provide additional optionality for organic growth or monetization as market conditions allow.

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

Based on production per employee, the PAMC is a productive and efficient coal mining complex in NAPP, averaging 7.50 tons of coal production per employee hour for the past two years. We believe our substantial capital investment in the PAMC will enable us to maintain high production volumes, low operating costs and a strong safety and environmental compliance record, which we believe are key to supporting stable financial performance and cash flows throughout business and commodity price cycles.

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

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

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Strong, Well-Established Customer Base Supporting Contractual Volumes

We have a well-established and diverse customer base, comprised of export industrial customers, metallurgical end-users and domestic electric-power-producing companies. 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. Approximately 96% of our sales in 2023 were to customer companies that were in our 2022 portfolio, and six of our top domestic power plant customers in 2023 (which are included in the ten plants to which we shipped approximately 500,000 tons or more of PAMC coal in 2023) 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.

In addition to our robust domestic customer base, we also have a growing international customer base due to favorable access to seaborne coal markets and our strong relationships with leading coal trading, brokering and international coal end-users. We have grown our exports of coal to the seaborne markets from 8.3 million tons (or approximately 32% of our annual sales volume) in 2017 to 16.2 million tons (or approximately 61% of our annual sales volume) in 2023, including sales from both the PAMC and the Itmann Mining Complex.

Highly Experienced Management Team and Operating Team

Our management and operating teams have (i) significant expertise owning, developing and managing complex thermal and metallurgical coal mining operations, (ii) valuable relationships with customers, railroads and other participants across the coal industry, (iii) technical wherewithal and demonstrated success in developing new applications and customers for our coal products in industrial, metallurgical and power generation markets, and (iv) a proven track record of successfully financing, 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 and innovating to create long-term growth and diversification opportunities.

Mining Properties

Information concerning our mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires us to disclose our mineral resources and our mineral reserves as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.

As used in this Annual Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. As such, you are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Likewise, you are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. We have used the term “coal” as in “coal reserves” and “coal resources” interchangeably with “mineral”.

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

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The information that follows relating to our individually material properties – PAMC, Itmann Mining Complex, Mason Dixon Mine, and River Mine – is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRSs”) relating to such properties prepared in compliance with Item 601(b)(96) and subpart 1300 of Regulation S-K by the John T. Boyd Company. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRSs, incorporated herein by reference, made a part of our 2021 Annual Report on Form 10-K and in part, updated within our 2022 Annual Report on Form 10-K.

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

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

The following tables provide a summary of all the Company's coal reserves and resources as of the end of the fiscal year ended December 31, 2023:

SUMMARY COAL RESERVES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2023


	Coal Reserves (tons in millions)
	Proven	Probable	Total
PAMC:
Bailey	56.9	80.5	137.4
Enlow Fork	214.5	33.5	248.0
Harvey	103.3	94.8	198.1
Total PAMC	374.7	208.8	583.5
Itmann Mining Complex	16.0	12.4	28.4
Other NAPP	3.6	19.7	23.3
Other CAPP	56.6	20.0	76.6
Total	450.9	260.9	711.8

SUMMARY COAL RESOURCES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2023


	Coal Resources (ton in millions)
	Measured	Indicated	Measured + Indicated	Inferred	Total

Mason Dixon Mine	106.6	158.4	265.0	8.9	273.9
River Mine	46.2	498.3	544.5	66.1	610.6
Other CAPP	44.3	66.3	110.6	1.9	112.5
Other ILB	106.6	137.7	244.3	0.6	244.9
Total	303.7	860.7	1,164.4	77.5	1,241.9

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

CONSOL Energy Recoverable Coal Reserves and Coal Resources

by Product (in Millions of Tons) as of December 31, 2023


Metallurgical	<1.0% Sulfur		>1.0% <1.5% Sulfur		>1.5% Sulfur		Total		Percent By Product
By Rank:
High Vol Bituminous	68.0		61.1		23.3		152.4		7.8	%
Med Vol Bituminous	14.4		5.6		—		20.0		1.0	%
Low Vol Bituminous	44.8		23.6		—		68.4		3.5	%
Total Metallurgical	127.2		90.3		23.3		240.8		12.3	%
Thermal	< 1.20 lbs. S02/MMBtu		> 1.20 < 2.50 lbs. S02/MMBtu		> 2.50 lbs. S02/MMBtu		Total		Percent By Product
By Region:
NAPP	—		—		1,468.0		1,468.0		75.2	%
ILB	—		44.2		200.7		244.9		12.5	%
Total Thermal	—		44.2		1,668.7		1,712.9		87.7	%
Total	127.2		134.5		1,692.0		1,953.7		100.0	%
Percent of Total	6.5	%	6.9	%	86.6	%	100.0	%

Internal Controls Disclosure

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

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

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

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

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Pennsylvania Mining Complex

Pennsylvania Mining Complex. The Pennsylvania Mining Complex is located approximately 26 miles southwest of Pittsburgh, near the city of Washington and the borough of Waynesburg, all in Pennsylvania, and consists of three deep longwall mining operations - the Bailey Mine, the Enlow Fork Mine and the Harvey Mine - as well as a centralized preparation plant located at approximately 39°58’23.7” N latitude and 80°24’43.6” W longitude. The Company controls approximately 179,181 acres of mineral and/or surface rights as a complex collection of owned and/or leased tracts that range from less than an acre to several hundred acres in size covered by various coal deeds and coal lease agreements. Lease terms generally extend until all the coal is removed from the subject tract. Where applicable, royalty rates typically range from 3% to 8% of the gross sales price of the coal. The Company maintains the right to mine and remove almost all of the Pittsburgh Seam within the PAMC boundaries. As part of the PAMC, CONSOL controls surface rights to approximately 17,665 acres through fee simple ownership. This includes ownership of the property upon which the surface facilities for mine access, processing, storing, and shipping are located, as well as 3,509 permitted acres for coarse and fine refuse disposal facilities. Despite a lengthy ownership history dating back to the 1920s with the acquisition of certain coal leases by the Company’s predecessor, commercial operations at the PAMC did not begin until 1984. The total book value of the PAMC and its associated plant and equipment as of December 31, 2023 is approximately $1.4 billion.

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

Numerous permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities. Permits generally require that the Company post a performance bond in an amount established by the regulatory program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. As of December 31, 2023, the Company held more than $380 million in surety bonds to cover its obligations relating to mining and reclamation, mine subsidence, road repairs, stream restoration, water loss, and dam safety with respect to the PAMC.

Bailey Mine. As of December 31, 2023, the Bailey Mine’s assigned and accessible reserve base contained an aggregate of 137.4 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,937 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.86. 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, 2023, 2022 and 2021, the Bailey Mine produced 11.2, 11.6 and 11.8 million tons of coal, respectively.

Enlow Fork Mine. As of December 31, 2023, the Enlow Fork Mine’s assigned and accessible reserve base contained an aggregate of 248.0 million tons of clean recoverable coal with an average as-received gross heat content of approximately 13,014 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 3.04. 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. On April 14, 2020, the Company announced the temporary idling of the Enlow Fork Mine due to the weakness in coal demand and economic slowdown related to the COVID-19 pandemic, and only one of its longwalls was restarted during the third quarter of 2020. During the fourth quarter of 2022, the Enlow Fork's second longwall was restarted. For the years ended December 31, 2023, 2022 and 2021, the Enlow Fork Mine produced 8.7, 6.3 and 6.8 million tons of coal, respectively.

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Harvey Mine. As of December 31, 2023, the Harvey Mine’s assigned and accessible reserve base contained an aggregate of 198.1 million tons of clean recoverable coal with an average as-received gross heat content of approximately 12,944 Btu per pound and an approximate average pounds of sulfur dioxide per mmBtu of 4.07. 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, 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, 2023, 2022 and 2021, the Harvey Mine produced 6.2, 6.1 and 5.3 million tons of coal, respectively.

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

CONSOL ENERGY PENNSYLVANIA MINING COMPLEX

Recoverable Coal Reserves as of December 31, 2023 and 2022


	Reserve Class	As Received Heat Value (Btu/lb)	Owned		Leased		Recoverable Coal Reserves (As-Received)
Mine/Reserve		Range	(%)		(%)		Proven	Probable	12/31/2023	12/31/2022

PA Mining Operations
Bailey	Permitted	12,700 – 13,220	62	%	38	%	44.6	25.1	69.7	79.6
	Unpermitted	12,800 – 13,120	81	%	19	%	12.3	55.4	67.7	72.9
Enlow Fork	Permitted	12,670 – 13,330	100	%	—	%	63.8	6.1	69.9	80.3
	Unpermitted	12,670 – 13,250	98	%	2	%	150.7	27.4	178.1	181.2
Harvey	Permitted	12,960 – 13,190	100	%	—	%	17.5	1.4	18.9	24.6
	Unpermitted	12,720 – 13,110	93	%	7	%	85.8	93.4	179.2	183.5
Total Recoverable Coal Reserves							374.7	208.8	583.5	622.1

Itmann Mining Complex

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 at approximately 37°35’23.65” N latitude and 81°27’14.43” W longitude. The Company controls approximately 20,224 contiguous acres of mining rights (comprising 270 tracts), by ownership or lease, to the Pocahontas 3 seam (P3) and the Pocahontas 4 seam (P4). The majority (95%) of the acreage is held under coal leases with lengthy terms that are subject to industry standard royalties. The total book value of the Itmann Mining Complex and its associated plant and equipment as of December 31, 2023 is approximately $104.6 million.

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

The mine accesses the P3 and P4 seams using a box cut drift entrance near an outcrop along Still Run Hollow. The P3 and P4 seams have been and continue 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, 2023, the Itmann No. 5 Mine's assigned and accessible reserve base contained an aggregate of 28.0 million tons of clean recoverable coal, enough to allow for more than 30 years of full-capacity production. These reserves contain an approximate average quality on a dry basis of 0.98% sulfur, 7.2% ash, and 19.3% volatile matter. Development mining at the Itmann No. 5 Mine began in 2020. Coal from the Itmann No. 5 Mine is currently extracted by underground methods using 6 continuous miner units in 3 super sections to achieve expected future capacity of approximately 900 thousand clean tons per year. For the years ended December 31, 2023, 2022 and 2021, the Itmann No. 5 Mine produced 316 thousand, 164 thousand and 101 thousand tons of coal, respectively. Through July 2022, production from the Itmann No. 5 Mine was toll washed at a third-party preparation plant. The Itmann Mining Complex started up its own preparation plant and rail loadout

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during the third quarter of 2022, and the remainder of 2022 production was washed at this new facility and shipped via rail from the newly built loadout.

General access to the Itmann No. 5 Mine is via a well-developed network of primary and secondary roads serviced by state and local governments. These roads offer direct access to the mine and processing facilities and are typically open year-round. Primary vehicular access to the property is via State Route 10/16, which follows the north bank of the Guyandotte River. The Guyandotte Class I rail line runs along the south bank of the Guyandotte River. Sources of electrical power, water, supplies and materials are readily available. Electrical power is provided to the mines and facilities by a regional utility company. Water is recycled from the abandoned underground Itmann No. 1 and No. 2 Mines or supplied by water wells.

The Itmann Preparation Plant was constructed in 2022 and began processing coal in late September 2022. Coal is shipped from the Itmann No. 5 Mine via tandem trucks to the 600 raw TPH processing facility, which is located approximately 2.5 miles west of the mine along WV State Route 10/16. The plant includes clean coal material handling systems capable of handling up to 3,500 TPH of product along with a 3,500 TPH unit train loadout located on the Guyandotte Class I rail line, which can be served by both Norfolk Southern and CSX. Third-party coal is also trucked into the facility for processing, blending and shipment via rail or truck. CONSOL also controls an additional 0.4 million tons of Sewell Seam reserves in McDowell County, WV (Tug Fork), which have the potential to be economically mined and then transported to, processed and shipped via the Itmann preparation plant facility.

As of December 31, 2023, the Company held less than $1 million in surety bonds to cover its current obligations relating to mining and reclamation, mine subsidence, stream restoration, and water loss with respect to the Itmann No. 5 Mine, preparation plant facility and refuse area.

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

CONSOL ENERGY ITMANN MINING COMPLEX

Recoverable Coal Reserves as of December 31, 2023 and 2022


		Moisture Free Quality (%)			Recoverable Coal Reserves (As-Received)
					Owned (%)		Leased%)		Tons in Millions
Mine/Reserve	Reserve Class	Sulfur	Ash	Vol					Proven	Probable	2023 Total	2022 Total

Itmann Mining Complex
Itmann No. 5	Permitted	0.97	8.4	18.5	—	%	100	%	3.4	0.9	4.3	4.6
Itmann No. 5	Unpermitted	0.98	7.0	19.4	9	%	91	%	12.2	11.5	23.7	23.7
Tug Fork1	Permitted	0.84	5.3	20.2	—	%	100	%	0.4	—	0.4	0.4
Total Recoverable Coal Reserves									16.0	12.4	28.4	28.7

1 Tug Fork is located approximately 35 miles southwest of the Itmann preparation plant and raw tons are accessible to the Itmann preparation plant via truck haul.

Non-Operating Reserves and Resources

Mason Dixon and River Mine

The Company’s Mason Dixon and River Mine properties are greenfield sites located in Greene County, Pennsylvania and Marshall, Monongalia, and Wetzel counties, West Virginia. Geographically, the center of the Mason Dixon and River Mine properties is located at approximately 39°40’02.77” N latitude and 80°34’20.61” W longitude. The properties comprise over 220 square miles within the NAPP coal-producing region of the eastern United States; as such, they are among the largest undeveloped Pittsburgh Seam properties. On December 31, 2023, the Company's estimated potentially underground minable thermal coal resources for Mason Dixon and River Mine were 273.9 million tons and 610.6 million tons, respectively. The total book value of the Mason Dixon and River Mine properties as of December 31, 2023 is approximately $57.4 million.

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

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

Other Properties

The Company also holds other greenfield recoverable coal reserves and coal resources located in NAPP, CAPP and ILB, which are not deemed individually material and had an estimated 457.3 million tons of recoverable coal reserves and coal resources. The Company’s estimate includes recoverable high-vol, mid-vol or low-vol metallurgical coal reserves and resources of 99.9 million tons and 112.5 million tons, respectively. Additionally, worldwide demand for metallurgical coal allows some of our recoverable coal reserves and resources, currently classified as thermal coal but that possess certain qualities, to be sold as metallurgical coal. The extent to which we can sell thermal coal as crossover metallurgical coal depends upon a number of factors, including the quality characteristics of the reserve, the specific quality requirements and constraints of the end-use customer and market conditions (which affect whether customers are compelled to substitute lower-quality crossover coal for higher-quality metallurgical coal in their blends to realize economic benefits).

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

CONSOL Energy Non-Operating Recoverable Coal Reserves and Coal Resources

as of December 31, 2023 and 2022


	As Received Heat Value (Btu/lb)	Owned (%)		Leased (%)		Recoverable Coal Reserves (As-Received)
Property						Proven	Probable	12/31/2023	12/31/2022
NAPP	11,400 – 13,400	100	%	—	%	3.6	19.7	23.3	23.3
CAPP	12,400 – 14,100	87	%	13	%	56.6	20.0	76.6	68.0
Total Non-Operating Reserves						60.2	39.7	99.9	91.3


	As Received Heat Value (Btu/lb)	Owned (%)		Leased (%)		Recoverable Coal Resources (As-Received)
Property						Measured	Indicated	Inferred	12/31/2023	12/31/2022
Mason Dixon Mine	12,250 – 13,060	96	%	4	%	106.6	158.4	8.9	273.9	273.9
River Mine	12,790 – 13,100	100	%	—	%	46.2	498.3	66.1	610.6	610.6
CAPP	12,400 – 14,100	67	%	33	%	44.3	66.3	1.9	112.5	121.8
ILB	11,600 – 12,000	75	%	25	%	106.6	137.7	0.6	244.9	315.9
Total Non-Operating Resources						303.7	860.7	77.5	1,241.9	1,322.2

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, 2023, 2022 and 2021.

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	Total Royalty Tonnage	Total Royalty Income *
Year	(in thousands)	(in thousands)
2023	1,179	$	8,326
2022	1,030	$	9,877
2021	1,675	$	8,186

* Excludes advanced mining royalty payments received of $529, $381 and $475 during the years ended December 31, 2023, 2022 and 2021, respectively.

Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report, nor is it included in our reported recoverable reserves and resources.

Production

In the year ended December 31, 2023, 98.8% of the Company's production came from underground mines equipped with longwall mining systems. The Company employs longwall mining techniques in its underground mines where the geology is favorable and reserves are sufficient, namely, in the three mines located at the PAMC. 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 production volumes 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, 2023, 2022 and 2021, 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.


	Loadout Facility Location	Mine Type	Mining Equipment	Transportation	Tons Produced (in millions)			Year Established or Acquired
Mine					2023	2022	2021
PA Mining Operations
Bailey	Enon, PA	U	LW/CM	R R/B	11.2	11.6	11.8	1984
Enlow Fork	Enon, PA	U	LW/CM	R R/B	8.7	6.3	6.8	1989
Harvey	Enon, PA	U	LW/CM	R R/B	6.2	6.1	5.3	2014
Total					26.1	23.9	23.9

Itmann Mining Complex
Itmann No. 5 Mine	Itmann, WV	U	CM	T/R	0.3	0.2	0.1	2020

Total Company					26.4	24.1	24.0

Table may not sum due to rounding.


U	—	Underground
LW	—	Longwall
CM	—	Continuous Miner
R	—	Rail
R/B	—	Rail to Barge or Vessel
T/R	—	Truck to Rail

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Coal Marketing and Sales

The following table sets forth tons sold and average realized coal revenue per ton sold for the periods indicated:


	Years Ended December 31,
	2023		2022		2021
Total Coal Revenue (in millions)	$	2,106	$	2,019	$	1,092
PA Mining Operations Tons Sold (in millions)	26.0		24.1		23.7
Average Realized Coal Revenue per Ton Sold – PA Mining Operations	$	77.74	$	69.89	$	45.75
Itmann Mining Complex Tons Sold (in millions)	0.5		0.2		0.1
Coal Revenue per Ton Sold – Itmann Mining Complex	$	158.71	$	219.44	$	70.40

We sell coal produced by our mines and additional coal that is purchased by us from other producers. Approximately 32% of our 2023 coal revenue was from U.S. electric generators, 66% of our 2023 coal revenue was from export markets and 2% of our 2023 coal revenue was from other domestic customers. Approximately 45% of our 2022 coal revenue was from U.S. electric generators, 53% of our 2022 coal revenue was from export markets and 2% of our 2022 coal revenue was from other domestic customers. Approximately 50% of our 2021 coal revenue was from U.S. electric generators, 46% of our 2021 coal revenue was from export markets and 4% of our 2021 coal revenue was from other domestic customers.

We had sales to approximately 50 customers from our coal operations during the past two years. During 2023, two customers each comprised over 10% of our total sales, aggregating approximately 23% of our total sales. During 2022, two customers each comprised over 10% of our total sales, aggregating approximately 30% of our total sales.

Coal Contracts and Pricing

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

Domestic coal revenue tends to be derived from contracts that typically have a term of one year or longer, and the pricing is typically fixed. Historically, export coal revenue tended to be derived from spot or shorter-term contracts with pricing determined closer to the time of shipment or based on a market index; however, the Company has secured several long-term export contracts with varying pricing arrangements.

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 2023 sales tons, approximately 61% were sold to export markets and 39% were sold to domestic customers. Of our 2023 sales tons, 49% were sold in the electric power generation market, 39% were sold in the industrial market and 12% were sold in the metallurgical market.

During the past two years, on realized coal revenue, a non-GAAP financial measure, of $2.0 billion in 2023 and $1.7 billion in 2022, our average realized coal revenue per ton sold, a non-GAAP financial measure, for coal produced from the PAMC was $77.74/ton in 2023 and $69.89/ton in 2022. Please see the section titled “Management's Discussion and Analysis of Financial Condition and Results of Operations - How We Evaluate Our Operations” for a reconciliation of realized coal revenue and average realized coal revenue per ton sold to total coal revenue, the most directly comparable measure calculated in accordance with GAAP. Pricing for our product depends strongly on conditions in the domestic and international thermal and metallurgical coal markets.

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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. Natural gas prices, coupled with increased capacity from new natural gas combined-cycle power plants and renewable energy sources, put pressure on power prices and on the demand for coal-fired electric power generation. These factors can affect the prices that we are able to achieve in the domestic thermal markets.

Similarly, imbalances in global supply and demand for energy fuels can cause substantial variability in pricing in the export markets we serve, which include industrial, metallurgical and power generation applications. The prices we are able to achieve in these export markets depend on a number of factors, including: (i) the supply-demand balance of seaborne thermal coal, specifically high calorific value coals, (ii) the supply-demand balance of seaborne metallurgical coal, (iii) prices for other competing sources of energy used in certain industrial applications, such as petroleum coke and metallurgical coal, (iv) prices for other competing sources of energy used for electricity generation, such as natural gas, (v) prices for other export coals that compete in these same markets, and (vi) pricing under our longer-term contracts, which may have been entered into under different market conditions.

Terminal Services

In 2023, approximately 19.0 million tons of coal were shipped through the CONSOL Marine Terminal owned by our subsidiary, CONSOL Marine Terminals LLC. Approximately 84% of the tonnage shipped was produced by the Pennsylvania Mining Complex. The terminal can either store coal or load coal directly into vessels from rail cars. It is also the only major coal terminal located on the east coast of the United States served by two railroads, Norfolk Southern and CSX. The CONSOL Marine Terminal has storage capacity of 1.1 million tons with more than thirty acres of capacity for stockpiles. The facility possesses blending capabilities, and it has transloaded approximately 13.9 million tons of coal per year on average over the past five years, with a throughput capacity of approximately 20 million tons.

Non-Core Coal Assets and Surface Properties

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

Distribution

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

Seasonality

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

Competition

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

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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 international coal consumers and the domestic electric generation industry. 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 fuel sources.

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

Human Capital Management

As of December 31, 2023, we had 2,020 employees, of which 40 CONSOL Marine Terminal employees were represented by a collective bargaining agreement. We believe our efforts in managing our workforce have been effective, evidenced by a strong culture and a good relationship between the Company and our employees.

Health and Safety. The success of our business is fundamentally connected to the well-being of our people. Accordingly, we are committed to the health, safety and wellness of our employees. We provide our employees and their families with access to health and welfare programs, including benefits that support their physical and mental health by providing tools and resources to help them improve or maintain their health status.

Talent. Through our long operating history and experience with technological innovation, we appreciate the importance of retention, growth and development of our employees. Our approach to talent is to both develop talent from within and supplement with external hires. We believe this method has yielded loyalty and commitment in our employee base, which in turn grows our business, while at the same time, adding new employees and external ideas supports a continuous improvement mindset and contributes to our goals of having a diverse and inclusive workforce. We believe that having approximately 43% of the Company's workforce with at least 10 years of company service coupled with our average voluntary retention rate of 89% as of the end of fiscal year 2023 reflects the engagement of our employees.

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

Employee Development. The Company provides its employees with tools and development resources to enhance their skills and careers at the Company, including (i) encouraging employees to discuss their professional development and identify interests or possible cross-training areas during annual performance reviews with their supervisors, (ii) providing a tuition aid program for educational pursuits related to present work or possible future positions, (iii) providing talent review and succession planning, and (iv) providing opportunities for on-the-job growth, through stretch assignments or temporary projects outside of an employee's typical responsibilities.

Laws and Regulations

Overview

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

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

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

In recent years, multiple regulations impacting our operations, or our customers' operations, have been subject to revision, repeal and judicial challenge. However, the extent to which these regulations will take effect or survive future presidential administrations is uncertain. In addition, presidential administrations, including the Biden Administration, could, independent of the regulatory process, issue Executive Orders or other Presidential Directives having the force of law that could immediately impact our business or our customers' business. For example, pursuant to the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (“Environment Executive Order”), which was issued in January 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. Implementation of the Environment Executive Order is ongoing, with multiple rulemakings expected to continue in 2024. Reversal or reinstatement of earlier regulations, or other presidential executive action, could impact our ability to obtain, maintain or renew permits, could reduce fossil fuels' share of power generating capacity, could expedite the retirements of fossil fuel-fired electric generating units, or could reduce the demand for our product in metallurgical and industrial markets, which could have a material adverse effect on our business, financial condition and results of operations.

Environmental Laws

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

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

Mercury and Air Toxics Standards Rule. In 2012, the United States Environmental Protection Agency (“EPA”) promulgated or finalized several rules for National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) for new and existing coal-fueled and oil-fueled electric generating plants. The EPA's 2012 Mercury and Air Toxics Standards rule (“MATS Rule”) imposed MACT emissions limitations on Hazardous Air Pollutants (“HAPs”), such as mercury, acid gas HAPs, HAP metals and organic HAPs, for applicable facilities. The rule was challenged, and ultimately rejected by the U.S. Supreme Court in 2015, for failing to consider the costs imposed by the MATS Rule. In 2020, the EPA published the MATS Reconsideration Rule as final, reaffirming the agency's “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 was subject to legal challenge in multiple cases before the D.C. Circuit. In February 2022, the EPA published its proposed rule revoking the 2020 MATS Reconsideration Rule and reaffirming the “appropriate and necessary” supplemental finding, with a final rule published in 2023. Separately, the EPA published a notice of proposed rulemaking (“NPRM”) suspending, revising, or rescinding the rule's risk and technology review (“RTR”) in April 2023, with a final rulemaking expected in 2024. Any emissions limitations in the final rule or similar future rulemakings could require our customers to incur significant capital costs associated with installation of emissions

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control technologies, which could negatively affect the demand and prices for our coal, our business and results of operations.

National Ambient Air Quality Standards. The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for six “criteria pollutants” (including particulate matter (“PM”), nitrogen oxides (“NOx”), ozone, sulfur dioxide (“SO2”), lead and carbon monoxide) considered harmful to public health and the environment and to review these standards every five years. Areas that are not in compliance with these standards are considered “non-attainment areas.” The designation of new non-attainment areas could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans (“SIPs”) that require emission source identification and emission reduction plans. In 2020, the EPA finalized decisions to retain the 2015 NAAQS for ozone and PM; however, both decisions were subject to legal challenge. Related to the ozone NAAQS, in August 2023, the EPA announced that it would not complete its reconsideration of the 2020 decision to retain the NAAQS but would instead begin a new review of the ozone NAAQS that would incorporate the latest science. This new review will be ongoing throughout 2024, and the EPA has not said when it expects to issue a NPRM. Related to the PM NAAQS, in January 2023, the EPA published a NPRM revising and restricting the primary (public health-based) standard for fine particulate matter (“PM2.5”) with a final rule expected in 2024. In addition, rulemakings restricting the secondary (public welfare) NAAQS standards for NOx, SO2 and PM are expected in 2024. Final rules may trigger new nonattainment areas that would result in more stringent SIPs that require significant investment in emissions control technologies associated with our or our customers' operations, and could adversely affect our costs and the demand for our coal.

Cross-State Air Pollution Rule/Good Neighbor Plan. The Cross-State Air Pollution Rule (“CSAPR”), originally finalized in 2011, required the District of Columbia and 27 upwind states to limit emissions from electricity generating units (“EGUs”) that “contribute significantly” to ozone or fine particulate matter emissions in downwind states. The Final CSAPR Update for the 2008 Ozone NAAQS was published by the EPA in 2016 and imposed requirements to reduce emissions of NOx, an ozone precursor, in 22 states. Following litigation in the D.C. Circuit, the rule was remanded back to the EPA. To address the remand, the EPA published the Final Revised CSAPR Update Rule for the 2008 Ozone NAAQS in 2021. The 2021 rule established new, or amended existing, Federal Implementation Plans (“FIPs”) imposing further reductions of NOx emissions in 12 states.

In February 2023, the EPA issued its Final Disapproval of SIPs submitted by 21 states pursuant to the “good neighbor” provisions of the 2015 Ozone NAAQS. The EPA's determination was challenged by several states in the respective jurisdictions' federal court of appeals, and litigation is ongoing. Following these SIP disapprovals, in June 2023, the EPA published the final Federal Good Neighbor Plan for the 2015 Ozone NAAQS, which applies to fossil fuel EGUs in 22 states (beginning in 2023) and industrial facilities in 20 states (beginning in 2023). The 2023 Good Neighbor Plan, which modifies the CSAPR trading program for EGUs, requires participation in a revised NOx allowance trading plan as well as operation of existing, and installation of new, emissions control technologies. The 2023 Good Neighbor Plan is subject to multiple legal challenges and in February 2024, the Supreme Court will hear oral arguments on whether to stay the rule while challenges continue. As a result of the CSAPR, the Good Neighbor Plan and related rulemakings, our customers could incur significant compliance costs that may lead to accelerated EGU closures or fuel switching, which could adversely affect the demand for our coal.

Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units under CAA Section 111(d). In October 2015, the EPA published a final rule under section 111(d) of the CAA known as the Clean Power Plan (“CPP”), which required states to create systems that reduce carbon dioxide (“CO2”) emissions from existing fossil fuel-fired EGUs by 28% in 2025 and 32% in 2030, compared to 2005 levels. The CPP was subject to numerous legal challenges and was stayed by the U.S. Supreme Court, pending the D.C. Circuit's review of the rule. The D.C. Circuit never reviewed the CPP because the EPA decided to reconsider it.

Following its reconsideration of the CPP, in July 2019, the EPA published the Affordable Clean Energy (“ACE”) rule which repealed the CPP and 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, directed states to develop specific SIPs to implement the rule, and revised CAA section 111(d) regulations to give states greater authority regarding these plans. Several states and public interest groups filed petitions seeking review and reconsideration of the ACE rule. In March 2021, the D.C. Circuit issued its partial mandate vacating the ACE rule but leaving the CPP Repeal intact to allow time for the EPA to issue a new rule under section 111(d). Separately, the Supreme Court agreed to hear four consolidated legal appeals to the D.C. Circuit decision striking down the ACE rule. In June 2022, the Supreme Court issued its decision reversing the D.C. Circuit's ruling and limiting expansive interpretations of the EPA's authority under Section 111 of the CAA, while generally upholding the EPA's authority to regulate GHGs as air pollutants and remanding the case for further proceedings.

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On May 23, 2023, the EPA published a NPRM repealing the ACE Rule and promulgating GHG emission guidelines for existing fossil fuel-fired EGUs. A supplemental NPRM was published on November 20, 2023, with a final rule expected to follow in April 2024. If the proposed emission guidelines are finalized, fossil fuel-fired EGUs may be required to make substantial capital investment in technologies such as Carbon Capture and Storage (“CCS”) or the co-firing of natural gas with coal. Alternatively, to avoid these capital investments, EGU owners and operators can accelerate the closure of existing power plants or agree to curtail their use. Such actions could negatively affect the demand and prices for our coal, thereby having a material adverse impact on our business and results of operations.

New Source Performance Standards (“NSPS”) for Greenhouse Gas Emissions from New, Modified, or Reconstructed Fossil Fuel-Fired EGUs Under CAA Section 111(b). In October 2015, the EPA published a final rule limiting CO2 emissions from new, modified and reconstructed fossil fuel-fired EGUs under section 111(b) of the CAA and identifying partial CCS as BSER. The rule was subject to numerous legal challenges in the D.C. Circuit that continue to be held in abeyance pending the EPA's review of the rule. In December 2018, the EPA published a proposed rule proposing to change its BSER determination from partial CCS to use of a supercritical boiler but the EPA never took final action on that proposal. In January 2021, the EPA finalized its “Pollutant Specific Significant Contribution Finding (“SCF”) for Greenhouse Gas Emissions from New, Modified and Reconstructed Electric Utility Generating Units” rule, concluding that the EGU source category GHG emissions are significant and warrant regulation. Although the SCF rule was subsequently challenged in court, the case was ultimately vacated because Congress revoked the rule through the Congressional Review Act in June 2021. On May 23, 2023, the EPA published a NPRM proposing to retain the NSPS for coal-fired EGUs that was promulgated in 2015 and was based on partial CCS. While no new coal-fired power stations are currently under construction in the U.S., promulgation of rules limiting CO2 emissions or requiring deployment of advanced technologies such as CCS will promote continuation of this trend. A lack of investment in construction, modification or reconstruction of coal-fired EGUs could negatively affect the demand and prices for our coal, thereby having a material adverse impact on our business and results of operations.

Global Climate Change

Our customers' consumption of the coal we produce results in the emission of GHGs, 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, including imposition of taxes or fees and promulgation of regulations intended to reduce GHG emissions, have and are expected to continue to result in (i) the decreased utilization or accelerated closure of existing coal-fired EGUs, (ii) the increased utilization of alternative fuels or generating systems, (iii) a reduction or elimination of new coal-fired power plant construction in certain countries, or (iv) the advancement of technologies aimed toward replacing or minimizing the use of coal in industrial or metallurgical processes. Additionally, regulations intended to limit or reduce emissions of methane from coal mines (discussed below) could have a direct impact on our results of operations.

To date in the U.S., no legislation to comprehensively regulate 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.

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 a report from the Senate Democrats' Special Committee on the Climate Crisis, titled “The Case for Climate Action,” in August 2020. Both reports call for the U.S. to achieve net-zero emissions no later than 2050. In addition, the U.S. Global Change Research Program, a consortium of governmental departments and agencies, released the Fifth National Climate Assessment (“NCA”) on November 14, 2023. 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 U.S. weather and climate, while identifying certain measures that could reduce climate-related risks. While no regulatory actions have been issued as a result, the NCA, legislative committee or similar reports could be relied upon to justify policy or executive action in the future.

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

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Since 2011, the EPA has required active underground coal mines and certain support facilities exceeding a minimum GHG emission threshold, including our operations, to report annual emissions to the EPA under the Mandatory GHG Reporting Rule. These emissions are not currently regulated by the EPA. Previous petitions and judicial challenges seeking to compel the EPA to classify coal mines as stationary sources appropriate for regulation have been unsuccessful to date. If the EPA were to regulate coal mine methane emissions in the future, we may 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 final regulation and the degree of emission reduction prescribed. In June 2022, the EPA published a NPRM amending certain provisions of the Mandatory GHG Reporting Rule, with a supplemental NPRM published in May 2023. A final rulemaking is expected to follow in April 2024.

Separately, in April 2022, the SEC published a proposed rulemaking that would require registrants to disclose certain climate-related information in their registration statements and annual reports. The proposed rule prescribes disclosure of climate-related risks that are reasonably likely to have a material impact on a business, results of operations or financial condition, including, but not limited to, certain climate-related financial metrics, an accounting of direct and indirect GHG emissions and details of climate change targets and goals. The final rulemaking is expected to be published in 2024. In October 2023, California enacted a series of laws known collectively as the California Climate Accountability Package that requires disclosure of climate-related risks and an accounting of direct and indirect GHG emissions that applies to companies that do business in California and have revenue over certain thresholds. The California law is expected to apply to many companies in the U.S. In addition to challenges related to compliance burden and a lack of standardized quantification methods, climate disclosure rules like the SEC's proposed rule and the California laws could proliferate investment bias and practices by investors and financial institutions to exclude our securities from investment portfolios or increase our cost of capital, regardless of the Company's results, strategy or financial performance.

In the absence of sweeping federal legislation on GHG emissions in the United States, a number of states, governors, mayors and businesses have committed to broad goals for GHG reductions or requirements to deploy carbon-free or renewable sources of electricity. Such goals include those announced by multiple domestic utilities, including some of our customers, pledging to substantially reduce or to achieve net zero GHG emissions, to accelerate closure of existing coal-fired power generating stations, or to increase generating capacity from renewable sources. These goals could ultimately affect the demand and prices for our coal, as these customers seek to achieve such goals over time. At the state level, in October 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 would allow Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”). RGGI is a mandatory cap-and-trade program among 10 northeastern states to reduce CO2 emissions from the power sector. Similar to other mandatory cap-and-trade initiatives, such as California's cap-and-trade program, RGGI seeks to limit CO2 emissions annually, in order to achieve a prescribed long-term emissions reduction target. In cap-and-trade scenarios, power generators or other GHG emitters are required to purchase allowances, available through auction or a secondary market, that are equal to one ton of CO2 emissions, thereby increasing the cost of electric power generation and incentivizing the power generator to limit their CO2 emissions by combusting fewer fossil fuels, including coal.

In response to the Governor's Order, the Pennsylvania Environmental Quality Board (“PAEQB”) published a proposed rulemaking in November 2020 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”). In 2021, the PAEQB and the Pennsylvania Independent Regulatory Review Commission (“IRRC”) subsequently voted to adopt the regulation, which was published as final in April 2022 and was subject to immediate legal challenge. On November 1, 2023, the Pennsylvania Commonwealth Court issued its decision striking down Pennsylvania's participation in RGGI and determining that RGGI constitutes an illegal tax under the Pennsylvania Constitution. Following this decision, on November 21, 2023, Governor Josh Shapiro announced that the state will appeal the Commonwealth Court's decision. If allowed to proceed, the proposed Pennsylvania CO2 Budget Trading Program regulation could result in decreased demand or decreased prices for our domestic coal in the Commonwealth of Pennsylvania. Additional CO2 cap-and-trade programs, carbon taxes, or other regulatory and policy regimes, whether state, federal or international in nature, or similar business or customer-focused voluntary climate and GHG emission reduction goals could affect the future market for coal and lower overall coal demand.

At both the state and federal levels, environmental organizations, third parties and regulators have challenged permitting actions associated with new fossil fuel infrastructure, power plants, pipelines and shipping terminals, citing GHG emissions, the uncertainty surrounding the economic viability of these projects under future laws limiting CO2 emissions, or the failure to account for their climate change impacts. Challenges such as these could result in litigation, limit operational expansion efforts, create permitting delays or restrict coal shipments, any of which could materially impact production, cash flow and results of operations.

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Foreign governments, including the European Union and member countries, have adopted regulations governing GHG emissions. Independent of regulation, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”) became effective in 2005 and established a binding GHG emission reduction requirement for developed countries. The Kyoto Protocol has never been ratified by the U.S. Senate. Similarly, in December 2015, the U.S. and approximately 200 nations signed the international Paris Agreement, making voluntary commitments to limit or reduce GHG emissions in order to limit global warming below 2 degrees Celsius from temperatures in the pre-industrial era. After the Trump Administration announced the United States' withdrawal from the agreement in 2017, President Biden signed an Executive Order in January 2021 bringing the United States back into the Paris Agreement as an official party. The UNFCCC convened its 26th Conference of the Parties (“COP26”) in November 2021, and ultimately enacted the Glasgow Climate Pact to establish a framework for the voluntary international cooperation of countries to reduce GHG emissions and meet nationally determined contributions (“NDCs”) to the Paris Agreement's goals. The Pact was reaffirmed during the UNFCCC's COP27 in November 2022 and further memorialized with ratification of the UAE Consensus at the UNFCCC's COP28 in December 2023. Under the Consensus, signatories are called upon to achieve a 43% reduction in GHG emissions by 2030 (compared to 2019 levels) through actions such as the accelerated phase-down of unabated coal power and other measures that drive the transition away from fossil fuels in energy systems. As a result, nations are expected to revise and develop ambitious economy-wide NDCs by 2025, including plans to accelerate targets aligned with the Paris Agreement's temperature goals.

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

Clean Water Act

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

Under the CWA, citizens may sue permit holders for alleged discharges of pollutants not explicitly limited by permits issued pursuant to the National Pollutant Discharge Elimination System (“NPDES”). Citizens may also sue to enforce NPDES permit requirements. Since 2012, multiple citizen suits have been filed against various coal operators, alleging violations of numeric and narrative water quality standards that broadly prohibit effects to aquatic life. While the outcome of these suits cannot be predicted, the suits seek penalties and injunctive relief that could limit future discharges or require installation of capital intensive water treatment technologies that have high operating costs. Additional CWA requirements that could directly or indirectly affect our operations are summarized below.

Dredge and Fill Permits Under CWA Sections 401 and 404. In order to obtain a permit for certain coal mining activities, such as the construction of coal refuse areas and slurry impoundments that may result in impacts to waters of the United States, an operator may need to obtain a permit for the discharge of fill material from the Army Corps of Engineers (“ACOE”) under Section 404 of the CWA. In July 2023, the EPA proposed revisions to Section 404 Tribal and State Program Regulations, intending to streamline and clarify the requirements and steps necessary for states and Tribes to assume and administer programs protecting waterways from discharges of dredged or fill materials without a permit. The public comment period for the proposed rule closed in October 2023, and the final rule has not been issued. Currently, there are three states (Michigan, New Jersey and Florida), and no Tribes, that administer an approved Section 404 program. If the final rule is issued, more states and Tribes could implement their own dredge and fill management programs. Additional state or Tribal programs could result in our operations experiencing permitting delays or disapprovals or litigation, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

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Alternatively, for specific categories of activities determined to have minimal effects, the Company may be required to comply with Nationwide Permits from the ACOE. Through the CWA Section 401 Certification Program, state regulators have approval authority over federal permits authorizing discharges in state waters or impacts to aquatic resources and must certify that the activity will comply with water quality standards or other applicable requirements. In 2020, the EPA issued the 2020 CWA Section 401 Certification Rule, intending to clarify the scope of state regulatory authority and, under certain circumstances, allowing the EPA to certify projects regardless of state objection. The rule was vacated by the U.S. District Court for the Northern District of California in October 2021. In June 2022, the EPA published a proposed revised section 401 certification rule expanding the role of states, territories and Tribes in the certification process. The final 2023 CWA Section 401 Water Quality Certification Improvement Rule became effective on November 27, 2023 but has been challenged by states and regulated entities in ongoing litigation to enjoin its enforcement. As a result of the requirement to receive explicit authorization from the ACOE and the corresponding state regulatory authority before proceeding with certain mining or export terminal activities, our operations could experience permitting delays or disapprovals or could be subject to litigation, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Definition of Waters of the United States. In June 2015, the EPA issued a rule to clarify which waterways are subject to federal jurisdiction under the CWA, known as the Clean Water Rule. The rule was ultimately blocked by a federal appeals court and in 2020, the EPA and the ACOE published the Navigable Waters Protection Rule (“NWPR”) to revise the definition of “Waters of the United States” (“WOTUS”) and to redefine which waterbodies are subject to federal jurisdiction. The NWPR was vacated by multiple U.S. District Courts and in January 2023, the EPA and the ACOE issued a final rule redefining WOTUS in a manner generally consistent with the pre-2015 framework. On May 25, 2023, the Supreme Court issued its decision in Sackett v. EPA, which narrowed federal jurisdiction over land and water features. On August 29, 2023, the EPA and the ACOE issued a final rule to amend the 2023 “Revised Definition of Waters of the United States” and conform with the Sackett decision (the “Conforming Rule”). The Conforming Rule took effect immediately upon publication on September 8, 2023. However, the Conforming Rule itself does not define certain language from the Supreme Court's ruling, and could be expanded or face additional legal challenges in the future. Further revisions to the definition of WOTUS could impose additional permitting obligations or restrictions, require enhanced mitigation, or cause the Company to modify its operations, any of which could result in delayed permit approval timeframes or increased operational costs and compliance burden.

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

On September 26, 2023, The Sierra Club and several other environmental organizations filed a Petition for Rulemaking to Establish a Nationwide NPDES Permit for Uncovered Railcars Transporting Coal Pursuant to 33 U.S.C. § 1342(a). Should this Petition result in final rulemaking, it could impose permitting obligations or restrictions on our rail partners and could impact the time and costs associated with the transportation of our coal.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. The 2015 Effluent Limitations Guidelines and Standards (“ELG”) rule established the first federal limits on the levels of toxic metals in various power plant wastewater discharges and set zero-discharge requirements for certain waste streams. The rule was subject to legal challenge and certain portions of the rule were vacated by the U.S. Court of Appeals for the Fifth Circuit in 2019. Revisions to the 2015 ELG rule were published in October 2020 and established a voluntary incentive program which provides power plants until December 31, 2028 to (i) retire or (ii) implement changes required to achieve compliance with stringent effluent limits and standards. The rule is expected to significantly increase compliance costs for many coal-fired power plants and as a result, could accelerate facility closures. Certain domestic utilities, including some of our current customers, have announced plans to retire certain coal-fired power plants by 2028 as a result of the ELG rule. In August 2021, the EPA announced its intention to undertake a supplemental rulemaking and on March 29, 2023, the EPA published the proposed Supplemental ELG Rule, which further restricts the ELGs established by the 2020 ELG Reconsideration Rule and incorporates limitations for additional waste streams that were previously excluded. A final rule is expected to be published in April 2024.

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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 that have primary jurisdiction for enforcement of SMCRA, with oversight from OSM. The timing of SMCRA permit issuance is largely at the discretion of the regulatory authorities and is often related to the size and complexity of the operation for which approval is sought. In addition, numerous other permits from applicable state, federal or local authorities are required to conduct mining operations. Timing of permit issuance can also be influenced by public engagement in the permitting process, such as through comment, hearings, or legal interventions which could affect our operations. Permits can also be delayed, refused, or revoked if any entity under common ownership or control has unabated permit violations, including the mining and compliance history of officers, directors, and principal owners of the entity seeking permit approval. Under the laws applicable to our operations, substantial fines and penalties, including suspension or revocation of permits, and in severe cases, criminal sanctions, may be imposed for failure to comply.

Under federal and state laws, including SMCRA, we are required to obtain surety bonds or other acceptable security to secure payment of our long-term obligations, including mine closure and reclamation, mine water treatment, federal and state workers’ compensation costs, coal leases, or other miscellaneous obligations. Surety bonds are typically renewable on a yearly basis, and it is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral therefor. Over the past few years, the surety markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and/or fewer providers willing to underwrite policies and surety bonds. Terms have generally become unfavorable, including increases in the amount of collateral required to secure surety bonds. However, more recently, we have seen insurance rates stabilize and even decrease on certain lines of coverage, as new insurance carriers have entered the market, although there is no assurance that this stabilization or decrease will be sustained or continued. 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, 2023, we posted an aggregated $524 million in surety bonds for reclamation purposes, as well as approximately $140 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 $0.096 per ton for underground mined coal and became effective in October 2021. We recognized expense related to Abandoned Mine Reclamation Fund fees of $2 million for the year ended December 31, 2023.

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. A number of species native to our operating areas are protected under the ESA or other related laws and regulations. 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. Throughout 2022, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service published, or announced plans to publish, separate rules to rescind and revise the ESA critical habitat regulations and definitions finalized under the previous administration. Multiple NPRMs were published in June 2023, with final rules expected to be promulgated in April 2024. If more stringent or protective measures were required, or if additional critical habitat areas were designated, our operations could be exposed to additional requirements, increased operating costs or delayed approval timeframes.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to taking a “major Federal action,” which encompasses agencies' decisions on certain permitting applications that fall under federal jurisdiction. NEPA reviews require federal agencies to review the environmental impacts of their decisions, including those associated with GHG emissions and the effects of climate change. Agencies generally must issue either an Environmental Impact Statement (“EIS”) or an Environmental Assessment (“EA”), which may create delays in project review and authorization timeframes or increase the cost of compliance. In July 2020, the White House Council on Environmental Quality (“CEQ”) promulgated the NEPA Update Rule, a two-phase process seeking to streamline the NEPA process and minimize unnecessary litigation, cost, and

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delay for project proponents; however, the rule was subject to legal challenge. In April 2022, the CEQ published its “Phase 1” final rule, amending certain provisions of its regulations and restoring provisions that were in effect before being modified in the July 2020 NEPA Update Rule. A “Phase 2” rulemaking to address a broader range of issues raised in the 2020 rulemaking was published in July 2023 and is expected to be final in April 2024. Separately, in 2020, the CEQ published a “Draft NEPA Guidance on Consideration of Greenhouse Gas Emissions” to replace guidance previously issued in 2016. The draft guidance sought to clarify the scope of review federal agencies should undertake when considering the effects of GHG emissions under NEPA and was never published in final form. Certain Federal courts have held that GHGs must be considered under NEPA prior to a federal agency taking a “major Federal action.” In January 2023, the CEQ issued interim guidance regarding consideration of GHG emissions under NEPA, directing agencies to quantify all reasonably foreseeable emissions associated with a proposed action and reasonable alternatives, both direct and indirect.

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 into the environment. Our current operations, operations of our predecessors, or facilities to which we have sent waste materials could be subject to liability under CERCLA.

Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations affect coal mining by imposing requirements for the treatment, storage, transportation and disposal of certain wastes created throughout the coal mining process. Certain waste streams created throughout the mining process, such as coal refuse and coal cleaning wastes, are excluded from the regulatory definition of hazardous waste. Further, coal operations authorized under SMCRA are exempt from RCRA permitting requirements.

Coal Combustion Residuals. Byproducts of coal combustion, or coal combustion residuals (“CCR”), are regulated under RCRA. In April 2015, the EPA published regulations for the disposal of CCR (the “CCR Rule”) and classified CCR as “non-hazardous” waste. The CCR Rule was subject to legal challenge and was ultimately remanded to the EPA. In August 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closures between 2021 and 2028, depending on site-specific circumstances. Provisions exempting inactive impoundments at inactive facilities from the CCR Rule were vacated by the D.C. Circuit in 2018 and the EPA proposed additional rules addressing those specific provisions in May 2023. After the comment period ended in July 2023, the EPA posted a Notice of Data Availability in November 2023, seeking public comment through December 2023 on the proposed rule's data. In 2022 and 2023, the EPA denied requests from the majority of CCR facilities that sought approval to continue disposal of CCR and non-CCR waste streams, and instead, required the facilities to cease receipt of waste within 135 days of completion of public comment. Future determinations of the same nature, or similar actions in expected future rulemakings, could lead to accelerated, abrupt, or unplanned suspension of coal-fueled EGUs.

Further, the Water Infrastructure Improvements for the Nation (“WIIN”) Act authorized the EPA to establish a federal permitting program for states and territories that do not have an approved permitting program for CCR disposal under RCRA. Accordingly, the EPA published a proposed rule establishing a federal program in February 2020, with a final rule expected in March 2026. The CCR rules impose new requirements that would generally increase the cost of CCR management or require facility closure. The combined effect of the CCR rules and ELG regulations (discussed above) has compelled power-generating companies to close existing ash ponds and may force the closure of certain existing coal-burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

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

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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:

•the caching of additional supplies of self-contained self-rescuer devices underground;

•the purchase and installation of electronic communication and personal tracking devices underground;

•the purchase and installation of proximity detection devices on continuous miner machines;

•the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;

•the purchase of new fire-resistant conveyor belting underground;

•additional training and testing that creates the need to hire additional employees;

•more stringent rock dusting requirements; and

•the purchase of personal dust monitors for collecting respirable dust samples from certain miners.

In September 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 in December 2016, but in January 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.

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:

•current and former coal miners totally disabled from black lung disease;

•certain survivors of miners who have died from black lung disease; and

•a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of coal, at a rate of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. In January 2022, these rates expired and reverted back to pre-2008 levels, at $0.50 per ton for deep mined coal and $0.25 per ton for surface-mined coal, neither amount to exceed 2.0% of the gross sales price. However, the Inflation Reduction Act of 2022 made the higher rates (of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal) permanent, effective in October 2022. The Company recognized expense related to the Black Lung Excise Tax of $10.9 million, $8.6 million and $13.5 million for the years ended December 31, 2023, 2022 and 2021, respectively.

In December 2021, the Government Accountability Office (“GAO”) published a report entitled “Black Lung Benefits Program: Continued Inaction on Coal Operator Self-Insurance Increases Financial Risk to Trust Fund.” This report notes that the Department of Labor (“DOL”) took certain steps to improve its oversight of self-insured coal mine operators, but these efforts were complicated by the COVID-19 pandemic. The GAO states in the report that the DOL has not taken necessary action to prevent additional benefit liabilities from being transferred to the trust fund and recommends that the DOL act on recommendations made in 2020. In January 2023, the Office of Workers' Compensation Programs (“OWCP”) issued a Notice of Proposed Rulemaking to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts, and that it plans to solicit public comments for that proposal. A change in requirements for security posted for coal operator self-insurance could result in the Company being required to post additional security for its obligations.

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.

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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.

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 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.

ITEM 1A. Risk Factors

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 (not necessarily in order of importance or probability of occurrence) 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

•deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•volatility and wide fluctuation in coal prices based upon a number of factors beyond our control including future plans to eliminate coal-fired generation facilities, oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels;

•the effects pandemics may have on our business and results of operations and on the global economy;

•an extended decline in the prices we receive for our coal affecting our operating results and cash flows;

•our customers extending existing contracts or not entering into new long-term contracts for coal on favorable terms;

•our reliance on major customers;

•decreases in demand and changes in coal consumption patterns of industrial end users, metallurgical coal users and electric power generators;

•the availability and reliability of transportation facilities and other systems, disruption of rail, barge, processing and transportation facilities and other systems that deliver our coal to market and fluctuations in transportation costs;

•the impact of potential, as well as any adopted, regulations to address pollution and climate change, including any requirements relating to greenhouse gas emissions, on our operating costs as well as on the market for coal;

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•the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal operations;

•uncertainties in estimating our economically recoverable coal reserves;

•failure to obtain or renew surety bonds or insurance coverage on acceptable terms;

•exposure to employee-related long-term liabilities; and

•the risk of our debt agreements, our debt, access to capital markets and changes in interest rates affecting our operating results and cash flows.

Risks Related to Our Common Stock and the Securities Market

•uncertainty with respect to the Company's common stock, potential stock price volatility and future dilution;

•the consequences of a lack of, or negative, commentary about us published by securities analysts and media;

•uncertainty regarding the timing of any dividends we may declare;

•uncertainty as to whether we will repurchase shares of our common stock or outstanding debt securities;

•restrictions on the ability to acquire us in our certificate of incorporation, bylaws and Delaware law and the resulting effects on the trading price of our common stock; and

•inability of stockholders to bring legal action against us in any forum other than the state courts of Delaware.

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.

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:

•demand for electricity in the United States is impacted by industrial production, which, if weakened, would negatively impact the revenues, margins and profitability of our coal business;

•demand for metallurgical coal depends on coke and steel demand in the United States and globally, which, if weakened, would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell coal from the Itmann Mining Complex or our thermal coal as higher priced high volatile metallurgical coal;

•demand for coal used in industrial applications depends on demand for products such as cement and brick used in construction and infrastructure projects, which, if weakened, would negatively impact the revenues, margins and profitability of our coal business;

•the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal reserves, or for strategic acquisitions of assets; and

•a decline in our creditworthiness, which may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

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, the price and availability of alternative fuels and plans by electricity generators to shut down or move away from coal-fired generation. 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:

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•the market price for coal;

•changes in the consumption pattern of industrial consumers, electricity generators and residential end-users of electricity;

•weather conditions in our markets which affect the demand for thermal coal;

•competition from other coal suppliers;

•the price and availability of alternative fuels and sources for electricity generation, especially natural gas and renewable energy sources;

•with respect to thermal coal, the price and availability of natural gas and the price and supply of imported liquefied natural gas;

•technological advances affecting energy consumption;

•with respect to metallurgical coal, the overall demand for steel;

•the costs, availability and capacity of transportation infrastructure;

•overall domestic and global economic conditions, including the supply of and demand for domestic and foreign coal;

•international developments impacting supply of thermal and metallurgical coal, including supply side reforms promulgated in China, and continued expected growth in demand for seaborne metallurgical coal in India; and

•the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.

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

The COVID-19 pandemic had a severe adverse impact on our business and operations, resulting in an unprecedented decline in demand for our coal during a portion of 2020, driven by widespread government-imposed lockdowns. If a pandemic were to again become an acute, severe risk, this could lead to government shutdowns being reinstated, leading to a 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, which would have a material adverse effect on our operations and financial condition. COVID-19 and various governmental and private responses to the virus also led to widespread, global supply chain disruptions. During the 2021 and 2022 fiscal years and continuing into 2023, we encountered multiple delays as a result of the disruption of the global supply chain and the logistics infrastructure. These supply chain disruptions have previously caused and may continue to or again 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 extent to which pandemics may adversely impact our results of operations, cash flows and financial condition depends on future developments, which are highly uncertain and unpredictable. 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 equipment at our strategic operations, 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 satisfy our customer obligations and materially and adversely affect our results of operations.

We depend on several major pieces of mining equipment to produce, transport and prepare our coal for our customers, including, but not limited to, longwall mining systems, continuous mining units, our preparation plants 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. Disruptions in supply chains, increased demand and other factors have recently led to increases in these lead times and delays, which could reduce our production and therefore adversely affect our results of operations, financial condition and cash flows.

Additionally, coal production, transportation and preparation 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, whether as a result of increased demand, shortages caused by supply chain disruptions or general inflationary pressures, could impact our mining operating costs because we may have a limited ability to negotiate lower

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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, the risk of which is currently elevated due to economy-wide high inflation, 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, 2023, approximately 42% 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.

Although we have recently begun selling a significant portion of our coal in the export market, we remain somewhat exposed to risks associated with a concentrated customer base both domestically and globally. We derive a significant portion of our revenues from two customers, each of which accounted for over 10% of our total sales and aggregated approximately 23% of our total sales in fiscal year 2023.

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 significant 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.

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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 coal consumption patterns for steel production, electricity generation and industrial applications 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 2023, the domestic electric power sector accounted for approximately 91% of total U.S. coal consumption. In 2023, the Pennsylvania Mining Complex sold approximately 38% 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:

•general economic conditions, particularly those affecting industrial electric power demand, such as a downturn in the U.S. or international economy and financial markets;

•overall demand for electricity;

•indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;

•environmental and other governmental regulations, including those impacting coal-fired power plants;

•energy conservation efforts and related governmental policies; and

•other corporate environmental, social or governance initiatives to reduce dependency on and/or consumption of fossil fuels.

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 displaced a significant amount of coal-fired electric power generation and may continue to do so in the near term, particularly older, less efficient coal-fired power 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, government-imposed lockdowns designed to slow or contain the spread of contagious diseases or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.

Coal sold into the industrial markets is used in the cement and brick manufacturing process. Any deterioration in the U.S. or foreign cement and brick industries, including a decrease in demand for such products or concerns regarding the continued financial viability of these industries, could reduce the demand for our coal sold into those markets and could adversely impact the creditworthiness of our U.S. or foreign industrial customers and our ability to receive timely payments from these customers. In addition, we compete heavily against the price of petroleum coke into these industries and as the price of petroleum coke changes, that could positively or negatively affect our financial condition, results of operations and cash flows.

The metallurgical coal that we produce from the PAMC and the Itmann Mining Complex is sold to domestic and export customers involved in the production of steel. Any deterioration in conditions in the U.S. or foreign steel industries, including a decrease in demand for steel or concerns regarding the continued financial viability of the industry, could reduce the demand for our metallurgical coal and could adversely impact the creditworthiness of our U.S. or foreign metallurgical coal customers and our ability to receive timely payments from these customers. In addition, the steel

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industry's demand for coal is affected by a number of factors, including the variable nature of that industry's business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites or plastics. When steel prices are lower, the prices that we charge steel industry customers for our metallurgical coal may decline, which could adversely affect our financial condition, results of operations and cash flows.

The availability and reliability of modes of transportation and transportation facilities as well as 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 industrial end-users, electricity generators and to the more specialized metallurgical coal market, 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.

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Inflation could result in higher costs and decreased profitability.

The United States, European Union and other large economies have recently experienced inflation at a rate significantly higher than recent years. Current and future inflationary effects may be driven by, among other things, governmental stimulus and monetary policies, supply chain disruptions and geopolitical instability. This recent inflation has resulted in rising prices, including increases in freight rates, prices for energy and other costs, and has adversely impacted us and may further impact us negatively in the future. Sustained inflation could result in higher costs for transportation, energy, materials, supplies and labor. Our efforts to recover inflation-based cost increases from our customers may be hampered as a result of the structure of our contracts and the contract bidding process as well as competitive pressure in the industry, economic conditions and the countries to which we sell our export coal. Accordingly, substantial inflation may have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the U.S., which could increase our cost of debt borrowing in the future.

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, 2023, 2022 and 2021, approximately 66%, 53% and 46%, respectively, of our annual coal revenue was derived from customers who exported our coal outside of the United States. 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:

•changes in a specific country's or region's political, economic or other conditions;

•changes in U.S. government policy with respect to these foreign countries may inhibit export of our products and limit potential customers' access to U.S. dollars in a country or region in which those potential customers are located;

•we may experience difficulties in enforcing our legal contracts or the collecting of foreign accounts receivable in a timely manner and we may be forced to write off these receivables;

•tariffs and other barriers may make our products less cost competitive;

•potentially adverse tax consequences to our customers may damage our cost competitiveness;

•customs, import/export and other regulations of the countries in which our international customers are located may adversely affect our business;

•currency fluctuations may make our coal less cost competitive, affecting overseas demand for our coal, or may indirectly expose us to currency fluctuation risk; and

•geopolitical uncertainty or turmoil, including terrorism, war and natural disasters.

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 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.

Compliance with import and export requirements, the Foreign Corrupt Practices Act and other applicable anti-corruption laws may increase the risks of doing business internationally.

Because we sell a significant portion of our production in international markets, our operations and activities inside and outside the U.S., as well as the shipment of our products across international borders, require us to comply with a number of federal, state, local and foreign laws and regulations, which are complex and increase our risks of doing business internationally. These laws and regulations include import and export requirements, economic sanction laws, customs laws, tax laws and anti-corruption laws, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act. We cannot predict how these laws or their interpretation, administration and enforcement will change over time. There can be no assurance that our employees, contractors, agents, distributors, customers, payment parties or third parties working on our behalf will not take actions in violation of these laws. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions, and might adversely affect our business, financial condition, results of operations and cash flows. In addition, actual or alleged violations could damage our

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reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

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 our customers to replace coal 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, nitrogen oxides and carbon dioxide when it is burned. Complying with regulations on these emissions can be costly for our customers, including those in the industrial, metallurgical and power generation markets. In order to comply with emissions standards promulgated under the federal Clean Air Act or similar state regulations seeking to limit the emissions that are generated as a result of coal combustion, coal users could be required to install costly emissions control devices, use or purchase emission credits or allowances, curtail operations or switch to other fuels, each of which has limitations. Because thermal coal currently accounts for a significant portion of our sales, our results could be materially affected by the extent to which our customers incur costs associated with controlling or limiting emissions from the use of coal or switch to alternative fuels. Rulemakings such as the Cross State Air Pollution Rule (“CSAPR”), the National Ambient Air Quality Standards (“NAAQS”), or the New Source Performance Standards (“NSPS”) and other Clean Air Act regulations may decrease the demand for our coal in industrial, metallurgical or electric power generation markets in the future. For more information, please see “Laws and Regulations” under Item 1 above.

Regulation to address climate change (or emissions of greenhouse gases including carbon dioxide and methane) and uncertainty regarding such regulation may affect us directly or indirectly by increasing our operating costs, reducing the value of our coal assets and adversely impacting 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. Additionally, our coal mines release methane to the atmosphere during operations, in order to promote a safe working environment for our miners underground.

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. Additionally, the United States is a signatory to the United Nations-sponsored “Paris Agreement,” which requires nations party to the agreement to submit non-binding GHG emissions reduction goals every five years after 2020. President Biden further announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2021 at the 26th United Nations Climate Change Conference, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on GHGs other than carbon dioxide. The Pact was reaffirmed during the UNFCCC's 27th Conference of the Parties (COP27) in November 2022 and further memorialized with ratification of the UAE Consensus at the UNFCCC's COP28 in December 2023. Under the Consensus, signatories are called upon to achieve a 43% reduction in GHG emissions by 2030 (compared to 2019 levels) through actions that drive the transition away from fossil fuels in energy systems. In addition, several individual U.S. states have already adopted measures requiring GHG emission reductions within their boundaries. Other states have elected to participate in regional cap-and-trade programs like the RGGI in the northeastern U.S. On November 1, 2023, the Pennsylvania Commonwealth Court issued its decision striking down Pennsylvania's participation in RGGI and determining that RGGI constitutes an illegal tax under the Pennsylvania Constitution. Following this decision, on November 21, 2023, Governor Josh Shapiro announced that the state will appeal the Commonwealth Court's decision. Any significant legislative changes at the international, national, state or local levels designed to reduce GHG emissions 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.

These potential legislative changes, 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.

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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 GHG 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.

Additionally, if emissions of methane from coal mines are regulated 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.

We are subject to litigation seeking to hold energy companies accountable for the effects of climate change and may be subject to additional such litigation in the future.

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 multiple lawsuits brought by the City of Baltimore, the State of Delaware, the City of Annapolis, and Anne Arundel County, Maryland 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 these 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 other laws that govern our business may increase our costs of doing business 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 the protection of the environment. These include 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.

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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:

•variations in thickness of the layer, or seam, of coal;

•adverse geological conditions, including amounts of rock and other natural materials intruding into the coal seam that could affect the stability of the roof and the side walls of the mine;

•environmental hazards;

•equipment failures or unexpected maintenance problems;

•fires or explosions, including as a result of methane, coal, coal dust or other explosive materials and/or other accidents;

•inclement or hazardous weather conditions and natural disasters or other force majeure events;

•seismic activities, ground failures, rock bursts or structural cave-ins or slides;

•delays in moving our longwall equipment;

•railroad derailments and mandated delays;

•security breaches or terroristic acts; and

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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. Over the past few years, the insurance and surety markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and/or fewer providers willing to underwrite policies and surety bonds. Terms have generally become more unfavorable, including increases in the amount of collateral required to secure surety bonds. However, more recently, we have seen insurance rates stabilize and even decrease on certain lines of coverage, as new insurance carriers have entered the market, although there is no assurance that this stabilization or decrease will be sustained or continued. In addition, federal and state regulators are considering making financial assurance requirements more stringent and costly with respect to self-insured coal workers' pneumoconiosis, mine closure and reclamation security amounts. 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, and incurring additional rising costs to obtain and maintain such arrangements could have a material adverse effect on our business, financial condition, results of operations and cash flows. 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

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could have a material adverse effect on our business and results of operations. Further cost burdens on our ability to maintain adequate insurance and bond coverage may adversely impact our operations, financial position and liquidity.

The majority of our operating mines are part of a single mining complex 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 No. 5 Mine, located in CAPP in Wyoming County, West Virginia in 2020, a majority of our mining operations are conducted at our 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 and we may have conflicts with competing holders of mineral rights and rights to use adjacent, overlying or underlying lands.

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 laws 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 we have purchased vertical wells in the past, 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.

Our operations may also face potential conflicts with holders of other mineral interests such as coalbed methane, natural gas and oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal reserves and active operations, potentially creating conflicting interests between us and the holders of those interests. From time to time we acquire these minerals ourselves to prevent conflicting interests from arising. If, however, conflicting interests arise and we do not acquire the competing mineral rights, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. If we are unable to reach an agreement with the holders of such rights, or to do so on a cost-effective basis, we may incur increased costs, and our ability to mine could be impaired, which could materially and adversely affect our business, results of operations, financial condition 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

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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 and investors 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.

As a result of increased consideration of ESG practices, 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 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. 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. 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. There have also 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 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. Relatedly, banks and 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. 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. As such, our access to capital to fund our continuing operations and growth and diversification opportunities could become more restricted.

On October 13, 2021, we announced our Forward Progress sustainability initiative, which included targets to reduce our direct operating GHG emissions. Our interim goal is to reduce our direct operating GHG emissions (referred to as scope 1 and scope 2 emissions) on an absolute basis by 50% over a five-year period (or by the end of 2026), compared to 2019 baseline levels and measured as the rate of carbon dioxide equivalents (CO2e) emitted. In addition, we announced our long-term efforts to achieve net zero direct operating GHG emissions by 2040 or sooner if feasible. However, achieving these goals may prove more difficult or costly than expected, and we may not succeed in reaching our targeted reductions on the announced timetable, or at all. Although we are not legally bound by these goals, our failure to achieve our GHG emission reduction targets could damage our reputation with customers, investors, financial media and regulators and could cause investors that focus on positive ESG business practices and sustainability scores to disfavor purchasing our securities, which could result in a decline in the market price of our stock and further restrict our access to capital. Additionally, if we expend more funds than anticipated to achieve our GHG emission reduction targets, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Finally, a part of our business plan is to regularly and rigorously evaluate opportunities for acquisitions, joint ventures and other business arrangements in the coal industry and related industries that complement our core operations. We may face greater difficulties in finding partners for such acquisitions, joint ventures or other business arrangements if these potential partners are less willing or unwilling to enter into transactions with companies that have a low ESG or sustainability score or companies that engage in fossil fuel activities, which could have a material adverse effect on our ability to expand our business, and therefore, our financial condition, results of operations and cash flows could be negatively impacted.

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The Russia-Ukraine war, and sanctions brought by the United States and other countries against Russia, have caused significant market disruptions that may lead to increased volatility in the price of certain commodities, including oil, natural gas, coal and other sources of energy. In addition, global unrest, including the Israel-Hamas conflict, has the potential to cause disruption to the global supply chain that could adversely affect our exports.

February 24, 2022 marked a significant escalation in the Russia-Ukraine war. The extent and duration of the military conflict involving Russia and Ukraine, resulting sanctions and future market or supply disruptions in the region are impossible to predict, but could be significant and may have a severe adverse effect on the region. Globally, various governments have banned imports from Russia including commodities such as oil, natural gas and coal. Separately, in early October 2023, Hamas, a militant group in control of Gaza, and Israel began an armed conflict in Israel, the Gaza Strip, and surrounding areas, which threatens to spread to other Middle Eastern countries including Lebanon, Syria and Iran. The Hamas-Israel military conflict is ongoing, and its length and outcome are highly unpredictable. These events have caused volatility in the aforementioned commodity markets. Although the Company has not experienced any material adverse effect on its results of operations, financial condition or cash flows as a result of these conflicts or the resulting volatility as of the date of this report, such volatility, including market expectations of potential changes in coal prices and inflationary pressures on steel products, may significantly affect prices for our coal or the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers, like natural gas.

These conflicts, trade and monetary sanctions, as well as any escalation of either of these conflicts and future developments, could significantly affect worldwide market prices and demand for our coal and cause turmoil in the capital markets and generally in the global financial system. In addition, due to the increasing importance of exports to our business, a disruption in the supply chain or network we rely on to export our coal could adversely affect our business and result in lost sales and increased expenses. Our ability to export coal is dependent on third-party ocean-going container ships, rail, barge, air and trucking systems and, therefore, disruption in these logistics services because of global conflicts, including recent attacks in the Middle East on container ships, could adversely affect our financial performance and financial condition, negatively impacting sales, profitability and cash flows. Either of these risks could have a material adverse effect on our business, financial condition and results of operations, along with our operating costs, making it difficult to execute our planned capital expenditure program. Additionally, the geopolitical and macroeconomic consequences of these conflicts and associated sanctions cannot be predicted, but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for coal-fired electricity, steel made through the use of metallurgical coal or our coal generally, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations, financial condition and cash flows.

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 U.S. Government 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.

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We may be unsuccessful in finding suitable joint venture partners or acquisition targets or in 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 or the entry into joint ventures may be limited by both our ability to identify appropriate acquisition or partner candidates and our financial resources, including our available cash and borrowing capacity. Additionally, the assets and businesses we acquire or in which we take an ownership stake through a joint venture may be dissimilar from our existing lines of business. Acquisitions and joint venture operations 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 and joint ventures. Acquisitions, joint ventures and business expansions involve numerous risks, including the following:

•difficulties in the integration of the assets and operations of the acquired businesses;

•inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas;

•the possibility that we have insufficient expertise to engage in such activities profitably or without incurring inappropriate amounts of risk;

•potential lack of control over a joint venture's business decisions and operations; and

•the diversion of management's attention from other operating issues.

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.

Additionally, our participation in joint venture arrangements necessarily involves risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our or the joint venture's best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact our results of operations, financial condition, cash flows or impair our ability to recover our investment in the joint venture. Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational and other standards. Failure by non-controlled joint venture partners to adhere to operational standards that are equivalent to ours could unfavorably affect safety results, operating costs and productivity and accordingly, adversely impact our results of operations, financial condition and cash flows.

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. For example, 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 waters and wetlands, and under Section 401 of the Clean Water Act, affected states must certify that proposed activity under Section 404 will comply with water quality standards or other applicable requirements. Corps permits and state certifications are required for construction of slurry ponds, refuse areas, impoundments, and for various other mining activities. The Section 404/401 permitting process has become subject to increasingly stringent regulatory requirements and challenges by environmental organizations. Where authorization by a federal agency is required, the federal agency may be required under the National Environmental Policy Act to consider the GHG emissions associated with the proposed project, both directly and indirectly, and may incorporate such considerations in its approval or denial. 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.

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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 shut down 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. In addition, government inspectors, under certain circumstances, have the ability to order our operations to be shut down based on environmental considerations.

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. In addition, government inspectors, under certain circumstances, may have the ability to order our operations to be shut down based on a perceived or actual violation of regulations concerning hazardous substances and other matters related to environmental protection. 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, with multiple facilities 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, the Itmann 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 where required by law or regulation. 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, 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 depend on the services of key executives and any inability to attract and retain key management personnel could have a material adverse effect on our business.

Our future success depends upon the continued services of our executive officers, including our Chief Executive Officer and Chief Financial Officer, who have critical experience and relationships in the coal industry that we rely on to implement our business plan and growth strategy. Our ability to retain senior management has in the past been, and may in the future be, impacted by volatility in commodity prices and uneven business performance, which have negatively impacted our stock price, and therefore, our ability to use equity compensation as a retention tool. Additionally, the recent efforts of certain members of the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote divestment of fossil fuel equities, to encourage the consideration of ESG practices of companies in a manner that negatively affects coal companies and to pressure lenders to limit funding to companies engaged in the extraction of fossil fuel reserves may also negatively impact our ability to attract and retain

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key management personnel. Accordingly, we have entered into, and may need to enter into additional, retention or other arrangements that could be costly to maintain. While we have change-in-control agreements in place with our senior executives, there can be no assurance we will continue to retain their services and we may become subject to significant severance payments if our relationship with these executives is terminated under certain circumstances. Further, turnover, planned or otherwise, in these or other key leadership positions may materially adversely affect our ability to manage our business efficiently and effectively, and such turnover can be disruptive and distracting to management, may lead to additional departures of existing personnel and could have a material adverse effect on our operations and future profitability. Our ability to retain our key management personnel or to identify and attract additional management personnel or suitable replacements should any members of the management team leave or be terminated is dependent on a number of factors, including the competitive nature of the employment market and our industry. Any failure to retain key management personnel or to attract additional or suitable replacement personnel could cause uncertainty among investors, employees, customers and others concerning our future direction and performance and could have a material adverse effect on our business, financial condition and results of operations.

We have asset retirement obligations and obligations for long-term employee benefits. 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 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 $241 million at December 31, 2023. 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.

We also provide various long-term employee benefits to inactive and retired employees, and we accrue amounts for these obligations. At December 31, 2023, the current and non-current portions of these obligations included:

•postretirement medical and life insurance ($227 million);

•coal workers’ pneumoconiosis benefits ($170 million);

•pension benefits ($23 million);

•workers’ compensation ($48 million); and

•long-term disability ($7 million).

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.

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 and external consultants. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

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•geologic and mining conditions;

•historical production from the area compared with production from other producing areas;

•the assumed effects of regulations and taxes by governmental agencies;

•our ability to obtain, maintain and renew all required permits;

•future improvements in mining technology;

•assumptions governing future prices; and

•future operating costs, including the cost of materials and capital expenditures.

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 we have purchased vertical wells in the past, 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.

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.

As a result of the Murray Energy bankruptcy, the Company could be required to pay for certain liabilities previously acquired 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 of the sold companies included certain retiree medical liabilities under the Coal Industry Retiree Health Benefit 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 bankruptcy proceedings, Murray unilaterally entered into a settlement with the United Mine Workers of America 1992 Benefit Plan (the “1992 Benefit Plan”) to transfer retirees in the Murray Energy Section 9711 Plan to the 1992 Benefit Plan. This was approved by the bankruptcy court on April 30, 2020. On May 2, 2020, the 1992 Benefit Plan 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 “1992 Plan Lawsuit”). The Murray sale agreement includes

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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 entered into a settlement agreement with Murray and withdrew its claims in bankruptcy. On September 11, 2020, the Defendants in the 1992 Plan Lawsuit filed a Motion to Dismiss Plaintiffs' Second Amended Complaint which was denied by the Court on March 29, 2022. 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 Benefit Plan's suit; however, the outcome of these proceedings is uncertain.

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, 2023, our total long-term indebtedness was approximately $199 million, consisting of:

•$103 million under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (“MEDCO”) 5.75% revenue bonds due September 2025;

•$75 million under our Pennsylvania Economic Development Financing Authority (“PEDFA”) 9.00% Solid Waste Disposal Revenue Bonds due April 2028;

•$14 million associated with finance leases due through 2028; and

•$7 million of miscellaneous debt.

At December 31, 2023, no borrowings were outstanding under our 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:

•increasing our vulnerability to general adverse economic and industry conditions;

•requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, share buy-back programs, acquisitions, pay dividends, development of our coal reserves or other general corporate requirements;

•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

•placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and

•limiting our ability to implement our business strategy.

Our senior secured credit agreement and the indenture governing our PEDFA bonds 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 PEDFA bonds 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 PEDFA bonds 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 PEDFA bonds 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 could adversely affect our business.

The Federal Reserve raised the federal funds interest rate throughout 2022 and 2023 in its effort to take action against domestic inflation. Any indebtedness we incur in the future may expose us to increased interest rates, whether as a result of higher fixed rates at the time such a new instrument is entered into or because such new indebtedness accrues interest at a variable rate. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

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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, process and record financial and operating data, communicate with our employees and business partners, and 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. 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 fixed-price 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, size consistency, and certain metallurgical coal properties. 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 40 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

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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, and accordingly, have a material adverse effect on our business, results of operations and financial condition.

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:

•our quarterly or annual earnings, or those of other companies in our industry;

•actual or anticipated fluctuations in our operating results;

•changes in earnings estimates by securities analysts or our ability to meet those estimates or our earnings guidance;

•the operating and stock price performance of other comparable companies;

•overall market fluctuations and domestic and worldwide economic conditions;

•volatility resulting from geopolitical events, inflation, changes in interest rates and other macroeconomic events; and

•other factors described in these “Risk Factors” and elsewhere in this Annual Report on Form 10-K.

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 or other securities 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. 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.

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We cannot guarantee the timing, amount, or payment of dividends on our common stock in the future or that we will continue to repurchase shares of our common stock.

During 2022, we initiated the payment of quarterly dividends on our common stock. During 2023, we pivoted toward repurchases of shares of our common stock and away from the payment of quarterly dividends. The payment and amount of any future dividend is at the 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 return to declaring and paying dividends in the future in the amounts we have previously declared. We also have in place a program to repurchase, from time to time, the Company's outstanding shares of common stock in an aggregate amount of up to $1 billion until December 31, 2024, subject to certain limitations in the Company's debt agreements. Our repurchase program does not obligate us to repurchase any specific number of shares of common stock 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 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 the trading price of our common stock.

Your percentage of ownership in the Company 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. The Company filed an automatically effective shelf registration statement on Form S-3 with the SEC on February 11, 2022 that allows us to issue an indeterminate amount of securities including common stock, preferred stock, debt securities and warrants. The shelf registration statement is intended to provide the Company with increased financial flexibility and more efficient access to the capital markets. We cannot predict the effect, if any, that market sales of these securities or the availability of the securities will have on the prevailing market price of our common stock. Substantial sales of shares of our common stock or other securities into the public market, or the perception that those sales could occur, may cause the market price of our common stock to decline. Future issuances of our common stock, or other securities convertible into our common stock, may result in significant dilution to the proportionate ownership and voting power of our existing stockholders and could 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 continue to 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, often called “blank check 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.

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:

•the inability of our stockholders to act by written consent unless such written consent is unanimous;

•the inability of our stockholders to call special meetings;

•rules regarding how stockholders may present proposals or nominate directors for election at stockholder meetings;

•the right of our board of directors to issue preferred stock without stockholder approval; and

•the ability of our directors, and not stockholders, to fill vacancies (including those resulting from an enlargement of our board of directors) on our board of directors.

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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.

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 derivative action or proceeding brought on our behalf;

•any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

•any action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws;

•any action asserting a claim that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein; or

•any action asserting an internal corporate claim as defined in Section 115 of the DGCL.

Any person or entity purchasing or otherwise holding any interest in shares of our common 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.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 1C. Cybersecurity

Risk Management and Strategy

CONSOL Energy has a cybersecurity risk program that is based on industry standards and best practices managed by a dedicated staff and specialists that support this program. We have implemented a set of system, network and application-level controls to protect our corporate data and systems. These controls are monitored for cybersecurity risk events and incidents on a continuous basis by a dedicated staff of cybersecurity professionals and various third-party providers. These controls are updated as necessary to protect the Company. In addition, the Company also takes a proactive approach by monitoring cyber threat intelligence to stay informed regarding emerging risks. The cybersecurity risk program also utilizes third-party assessors, consultants and auditors to perform various services, such as tabletop exercises and network penetration tests. The Company provides awareness training to its employees to help identify, avoid and mitigate cybersecurity threats. Employees with network access participate quarterly in required training, including spear phishing and other awareness training. The program also has a policy in place to address vendor and third-party risk. Cybersecurity risk is also evaluated during the acquisition process for new products and services.

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CONSOL Energy accounts for cybersecurity risk as a part of the Company's overall business strategy and planning. The Board's Audit Committee, which oversees all matters related to risk management and, in particular, the security of and risks related to the Company's information technology systems, receives regular reports on the Company's cybersecurity risk management efforts from various senior officers of the Company. The Company also has a corporate cybersecurity risk Steering Committee, which is a cross-functional group comprised of both senior management and other key business unit leaders that provides input to senior management on the Company's cybersecurity risk program.

CONSOL Energy has not experienced any operational or financial impact as the result of a cybersecurity risk or incident and, at this time, the risks from cybersecurity threats are not reasonably likely to materially affect the Company's business strategy, results of operations or financial condition. However, it is prepared to mitigate and respond to such an event should it occur. CONSOL Energy has prepared a comprehensive Cybersecurity Incident Response Plan, as well as an Information Technology Disaster Recovery Plan. These plans are reviewed, updated and tested on a regular basis. Specifically, CONSOL Energy conducts cybersecurity tabletop exercises that include participation by Audit Committee members, senior management and third-party cybersecurity consultants.

The Company faces a range of cybersecurity threats including threats common to many industries, such as ransomware and denial of service, as well as more advanced threats specific to critical infrastructure industries such as mining. CONSOL Energy's customers, equipment suppliers, transportation facility providers and joint venture partners face similar cybersecurity threats, and a cybersecurity incident affecting the Company or any of these entities could materially affect our operations, performance and results of operations. The Company continues to invest in the cybersecurity and resiliency of its networks and to enhance its internal controls and processes, which are designed to help protect our systems and infrastructure, and the information they contain. For more information regarding the risks we face from cybersecurity, please see the section titled “Risk Factors - Terrorist attacks or cyber incidents could result in information theft, data corruption, operational disruption and/or financial loss.”

Governance

The CONSOL Energy Board of Directors has assigned oversight of cybersecurity risk to the Audit Committee, as outlined in the Committee's charter. Updates on the cybersecurity risk program are provided at each Audit Committee meeting. Additionally, CONSOL Energy's senior management engages with the Audit Committee on a regular basis to provide updates on our cybersecurity risk program.

The Company has a Cybersecurity Manager who reports directly to the Director of Information Technology. CONSOL Energy's Cybersecurity Manager has 25 years of industry experience and holds many relevant industry certifications. The Cybersecurity Manager has direct oversight of the cybersecurity risk program. Cybersecurity risk briefings are provided to the Audit Committee by the Director of Information Technology at all regular meetings. Additionally, the Director of Information Technology and Cybersecurity Manager communicate directly with the Audit Committee chair as needed to ensure adequate oversight of the program.

ITEM 2. Properties

See “Mining Properties” 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 275 Technology Drive, Suite 101, Canonsburg, Pennsylvania 15317-9565. 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.

ITEM 3. Legal Proceedings

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, other than those described in Note 23, “Commitments and Contingent Liabilities,” in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K, which descriptions are incorporated herein by this reference.

ITEM 4. Mine Safety Disclosures

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.

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PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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, 2024, there were 68 holders of record of our common stock. A substantially greater number of holders of our common stock are “street name” or beneficial holders, whose shares of record are held by banks, brokers and other financial institutions.

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., Alpha Metallurgical Resources, Inc. (formerly known as Contura Energy, Inc.), Hallador Energy Company, Peabody Energy Corporation, Ramaco Resources, Inc., and Warrior Met Coal, Inc.

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 December 31, 2018 through December 31, 2023.


	December 31, 2018	December 31, 2019	December 31, 2020	December 31, 2021	December 31, 2022	December 31, 2023
CONSOL Energy Inc.	100.0	45.8	22.7	71.6	210.9	339.0
S&P 500 Stock Index	100.0	128.9	149.9	190.2	153.3	190.4
Peer Group	100.0	62.9	41.3	122.8	264.4	412.3

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

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Repurchases of Equity Securities

The following table sets forth repurchases of the Company's common stock during the three months ended December 31, 2023:


	(a)	(b)		(c)	(d)
Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs (000s omitted) (2)
October 1, 2023 - October 31, 2023	142,935	$	104.94	142,935	$	488,174	(3)
November 1, 2023 - November 30, 2023	739,575	$	98.95	739,575	$	414,994	(3)
December 1, 2023 - December 31, 2023	361,117	$	104.72	361,117	$	377,179	(3)

(1) 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. Since the inception of the program, CONSOL Energy Inc.'s Board of Directors has amended the program on several separate occasions. As a result of such amendments, the Company may now repurchase up to $1 billion of its stock and debt until December 31, 2024. As of February 1, 2024, approximately $347 million remained available under the stock and debt repurchase program. The repurchases will be effected from time to time on the open market or in privately negotiated transactions or under a Rule 10b5-1 plan. The program does not obligate CONSOL Energy to acquire any particular amount of its common stock or notes, and the program can be modified or suspended at any time at the Company's discretion.

(2) Management cannot estimate the number of shares that will be repurchased because purchases are made based upon the Company's stock price, the Company's financial outlook and alternative investment options.

(3) In the three months ended December 31, 2023, CONSOL Energy utilized approximately $126 million to repurchase its common stock.

Dividends

In the fiscal year ended December 31, 2022, the Company initiated an enhanced shareholder capital return program through repurchases of shares of common stock and the payment of dividends. The Company currently intends, subject to the discretion of the Company's Board of Directors, to return a planned aggregate of approximately 75% of the Company's quarterly free cash flow in the form of share repurchases.

The declaration and payment of dividends by CONSOL Energy is at the discretion of CONSOL Energy's Board of Directors, and no assurance can be given that CONSOL Energy will return to declaring and paying 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. Certain of the Company's financing arrangements may limit CONSOL Energy's ability to pay dividends and repurchase stock based on certain covenants.

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.

ITEM 6. [Reserved.]

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ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The Company's discussion and analysis includes a comparison of the year ended December 31, 2023 to the year ended December 31, 2022. A similar discussion and analysis that compares year ended December 31, 2022 to the fiscal year ended December 31, 2021 may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference.

All amounts discussed are in millions of U.S. dollars, unless otherwise indicated. All tons discussed are on a clean coal equivalent basis.

2023 Highlights:

•Repurchased 5.2 million shares of CEIX common stock at a weighted average price of $75.69 per share.

•CONSOL Marine Terminal throughput volume of 19.0 million tons, including 15.7 million tons of PAMC coal shipments.

•Increased the Revolving Credit Facility capacity by $95.0 million with additional covenant flexibility.

•Debt repayments of $189.0 million, including payments on Second Lien Notes, Term Loan B, and equipment-financed and other debt of $99.1 million, $63.6 million and $26.3 million, respectively.

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) adjusted EBITDA, a non-GAAP financial measure; (ii) coal production and sales volumes; (iii) realized coal revenue, a non-GAAP financial measure; (iv) cost of coal sold, a non-GAAP financial measure; (v) cash cost of coal sold, a non-GAAP financial measure; (vi) average realized coal revenue per ton sold, an operating ratio derived from non-GAAP financial measures; (vii) average cash cost of coal sold per ton, an operating ratio derived from non-GAAP financial measures; and (viii) average cash margin per ton sold, an operating ratio derived from non-GAAP financial measures.

We believe that adjusted EBITDA provides a helpful measure of comparing our operating performance with the performance of other companies that have different financing, capital structures and tax rates than ours. We believe realized coal revenue, average realized coal revenue per ton sold, cost of coal sold, cash cost of coal sold, average cash cost of coal sold per ton, and average cash margin per ton sold normalize the volatility contained within comparable GAAP measures by adjusting for certain non-operating or non-cash transactions. We believe realized coal revenue and average realized coal revenue per ton sold provide useful information to investors because they better reflect our earnings by including the settled costs (or gains) of our commodity derivatives for the period. 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:

•our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis, tax rates or capital structure;

•the ability of our assets to generate sufficient cash flow;

•our ability to incur and service debt and fund capital expenditures;

•the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities; and

•the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

These non-GAAP financial measures should not be considered an alternative to operating and other costs, total coal revenue, net income, or any other measure of financial performance 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.

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Reconciliation of Non-GAAP Financial Measures

We evaluate our cost of coal sold and cash cost of coal sold on an aggregate basis by segment, and our average cash cost of coal sold per ton on a per-ton basis. 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. Cost of coal sold excludes any indirect costs 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. We define average cash cost of coal sold per ton as cash cost of coal sold divided by tons sold. The GAAP measure most directly comparable to cost of coal sold, cash cost of coal sold and average cash cost of coal sold per ton is operating and other costs.

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


	Years Ended December 31,
	2023		2022
Operating and Other Costs	$	1,120,065	$	949,222
Less: Other Costs (Non-Production and non-PAMC)	(180,173)		(114,817)
Cash Cost of Coal Sold	$	939,892	$	834,405
Add: Depreciation, Depletion and Amortization (PAMC Production)	190,962		189,857
Cost of Coal Sold	$	1,130,854	$	1,024,262
Total Tons Sold (in millions)	26.0		24.1
Average Cost of Coal Sold per Ton	$	43.42	$	42.49
Less: Depreciation, Depletion and Amortization Costs per Ton Sold	7.32		7.93
Average Cash Cost of Coal Sold per Ton	$	36.10	$	34.56

We evaluate our average realized coal revenue per ton sold and average cash margin per ton sold on a per-ton basis. We define realized coal revenue as total coal revenue, net of settlements of commodity derivatives. We define average realized coal revenue per ton sold as total coal revenue, net of settlements of commodity derivatives divided by tons sold. We define average cash margin per ton sold as average realized coal revenue per ton sold, net of average cash cost of coal sold per ton. The GAAP measure most directly comparable to realized coal revenue, average realized coal revenue per ton sold, and average cash margin per ton sold is total coal revenue.

The following table presents a reconciliation for the PAMC segment of realized coal revenue, average realized coal revenue 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).


	Years Ended December 31,
	2023		2022
Total Coal Revenue (PAMC Segment)	$	2,024,610	$	1,973,884
Less: Settlements of Commodity Derivatives	—		(289,228)
Realized Coal Revenue	2,024,610		1,684,656
Operating and Other Costs	1,120,065		949,222
Less: Other Costs (Non-Production and non-PAMC)	(180,173)		(114,817)
Cash Cost of Coal Sold	$	939,892	$	834,405
Total Tons Sold (in millions)	26.0		24.1
Average Realized Coal Revenue per Ton Sold	$	77.74	$	69.89
Less: Average Cash Cost of Coal Sold per Ton	36.10		34.56
Average Cash Margin per Ton Sold	$	41.64	$	35.33

We define adjusted EBITDA as (i) net income (loss) plus income taxes, interest expense and depreciation, depletion and amortization, as adjusted for (ii) certain non-cash items, such as stock-based compensation, loss on debt extinguishment and fair value adjustments of commodity derivative instruments. The GAAP measure most directly comparable to adjusted EBITDA is net income (loss).

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The following tables present a reconciliation of adjusted EBITDA to net income (loss), the most directly comparable GAAP financial measure, on a historical basis, for each of the periods indicated (in thousands).


	For the Year Ended December 31, 2023
Dollars in thousands	PA Mining Complex		CONSOL Marine Terminal		Other		Total Company
Net Income (Loss)	$	810,234	$	69,253	$	(223,595)	$	655,892

Add: Income Tax Expense	—		—		121,980		121,980
Add: Interest Expense	—		6,097		23,228		29,325
Less: Interest Income	(2,344)		—		(11,253)		(13,597)
Earnings (Loss) Before Interest & Taxes (EBIT)	807,890		75,350		(89,640)		793,600

Add: Depreciation, Depletion & Amortization	202,833		4,671		33,813		241,317

Earnings (Loss) Before Interest, Taxes and DD&A (EBITDA)	$	1,010,723	$	80,021	$	(55,827)	$	1,034,917

Adjustments:
Add: Stock-Based Compensation	$	8,438	$	301	$	1,307	$	10,046
Add: Loss on Debt Extinguishment	—		—		2,725		2,725
Total Pre-tax Adjustments	8,438		301		4,032		12,771

Adjusted EBITDA	$	1,019,161	$	80,322	$	(51,795)	$	1,047,688


	For the Year Ended December 31, 2022
Dollars in thousands	PA Mining Complex		CONSOL Marine Terminal		Other		Total Company
Net Income (Loss)	$	620,208	$	41,223	$	(194,452)	$	466,979

Add: Income Tax Expense	—		—		101,458		101,458
Add: Interest Expense	—		6,116		46,524		52,640
Less: Interest Income	(1,857)		—		(4,174)		(6,031)
Earnings (Loss) Before Interest & Taxes (EBIT)	618,351		47,339		(50,644)		615,046

Add: Depreciation, Depletion & Amortization	200,320		4,604		21,954		226,878

Earnings (Loss) Before Interest, Taxes and DD&A (EBITDA)	$	818,671	$	51,943	$	(28,690)	$	841,924

Adjustments:
Add: Stock-Based Compensation	$	6,628	$	316	$	946	$	7,890
Add: Loss on Debt Extinguishment	—		—		5,623		5,623
Add: Equity Affiliate Adjustments	—		—		3,500		3,500
Less: Fair Value Adjustment of Commodity Derivative Instruments	(52,204)		—		—		(52,204)
Total Pre-tax Adjustments	(45,576)		316		10,069		(35,191)

Adjusted EBITDA	$	773,095	$	52,259	$	(18,621)	$	806,733

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Results of Operations: Year Ended December 31, 2023 Compared with the Year Ended December 31, 2022

Revenue and Other Income


	For the Year Ended December 31,
(in millions)	2023		2022		Variance
Coal Revenue - PAMC	$	2,025	$	1,974	$	51
Coal Revenue - Itmann Mining Complex	82		45		37
Terminal Revenue	106		79		27
Freight Revenue	294		182		112
Total Revenues from Contracts with Customers	2,507		2,280		227
Loss on Commodity Derivatives, net	—		(237)		237
Miscellaneous Other Income	53		24		29
Gain on Sale of Assets	9		35		(26)
Total Revenue and Other Income	$	2,569	$	2,102	$	467

Revenues from Contracts with Customers

Revenues from contracts with customers were $2,507 million for the year ended December 31, 2023, compared to $2,280 million for the year ended December 31, 2022.

On a consolidated basis, coal revenue for the year ended December 31, 2023 was $2,107 million, which consisted of $2,025 million from the Pennsylvania Mining Complex and $82 million from the Itmann Mining Complex. The $2,107 million of coal revenue was sold into the following markets: $1,019 million into power generation, $773 million into industrial, and $315 million into metallurgical. The Company had consolidated coal revenue of $2,019 million for the year ended December 31, 2022, which consisted of $1,974 million from the Pennsylvania Mining Complex and $45 million from the Itmann Mining Complex. The $2,019 million of coal revenue was sold into the following markets: $1,303 million into power generation, $411 million into industrial, and $305 million into metallurgical.

During the year ended December 31, 2023, the Company continued to diversify its portfolio by placing a growing portion of its production into the export markets, where it sells to industrial, metallurgical and power generation end-users. The domestic power generation market has experienced reduced coal consumption in recent years as a result of depressed domestic natural gas pricing and milder winters, both of which reduce coal demand. The pivot to the export markets provides the Company with pricing upside when markets are strong and with volume stability when markets are weak. In the year ended December 31, 2023, the Company placed 16.2 million tons of coal, or 61% of its total tons sold, into the export market. Comparatively, in the year ended December 31, 2022, the Company placed 10.7 million tons of coal, or 44% of its total tons sold, into the export market. See “Operational Performance” for further information about segment results.

The Company’s Terminal revenue consists of fees charged for coal loaded at the CONSOL Marine Terminal, which is located in the Port of Baltimore, Maryland, and provides access to international coal markets. Terminal revenues are generated from providing transloading services from rail to vessel or barge, temporary storage or stockpile facilities, as well as blending, weighing, and sampling. Terminal revenues were $106 million for the year ended December 31, 2023, compared to $79 million for the year ended December 31, 2022. See “Operational Performance - CONSOL Marine Terminal Analysis” for further information about segment results.

The Company recognizes freight revenue as 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, to which the Company contractually provides transportation services to move its coal from the mine to the ultimate sales point. Freight revenue is completely offset by freight expense. Freight revenue and freight expense were both $294 million for the year ended December 31, 2023, compared to $182 million for the year ended December 31, 2022. The $112 million increase was primarily related to increased transportation costs associated with the aforementioned increase of sales into the export market.

Loss on Commodity Derivatives, net

As of December 31, 2022, all of the Company's coal-related derivative contracts have settled and the Company has not entered into any additional coal-related derivative contracts. During the year ended December 31, 2022, the Company settled a portion of its coal-related derivatives at a loss of $289 million and recognized fair value adjustments of its

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commodity derivative instruments of $52 million. See “Operational Performance - PAMC Analysis” for further information about segment results.

Miscellaneous Other Income

Miscellaneous other income was $53 million for the year ended December 31, 2023, compared to $24 million for the year ended December 31, 2022. The change is due to the following items:


	For the Year Ended December 31,
	2023		2022		Variance
Contract Buyouts	$	16	$	—	$	16
Interest Income	14		6		8
Royalty Income - Non-Operated Coal	9		10		(1)
Other Income	14		8		6
Miscellaneous Other Income	$	53	$	24	$	29

Contract buyout income was primarily the result of partial contract buyouts that involved negotiations with several customers to reduce coal quantities for which they were otherwise obligated to purchase under contracts in exchange for payment of certain fees to the Company and did not impact forward contract terms.

Interest income increased primarily due to the Company's investment in marketable debt securities, primarily comprised of highly liquid U.S. Treasury securities, during the year ended December 31, 2023.

The increase in other income was related to shortfall payments at the CONSOL Marine Terminal and various other items, none of which were individually significant.

Gain on Sale of Assets

Gain on sale of assets was $9 million for the year ended December 31, 2023, compared to $35 million for the year ended December 31, 2022. The $26 million decrease was due to the sale of certain coal assets during the year ended December 31, 2022.

Operating and Other Costs

On a consolidated basis, operating and other costs were $1,120 million for the year ended December 31, 2023, compared to $949 million for the year ended December 31, 2022. Operating and other costs increased in the period-to-period comparison due to the following items:


	For the Year Ended December 31,
	2023		2022		Variance
Operating Costs - PAMC	$	940	$	834	$	106
Operating Costs - Itmann Mining Complex	99		42		57
Operating Costs - Terminal	27		25		2
Coal Reserve Holding Costs	16		10		6
Employee-Related Legacy Liability Expense	12		7		5
Closed and Idle Mines	5		4		1
Equity Affiliate Adjustments	—		4		(4)
Other	21		23		(2)
Operating and Other Costs	$	1,120	$	949	$	171

Operating costs for the Pennsylvania Mining Complex include items such as direct operating costs, royalties and production taxes and direct administration costs. In the period-to-period comparison, operating costs - PAMC increased $106 million, primarily due to the added costs of the fifth longwall, which was brought online at the end of the fourth quarter of 2022, and ongoing inflationary pressures. See “Operational Performance - PAMC Analysis” for further information on segment operating costs.

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Operating costs for the Itmann Mining Complex primarily consist of costs related to produced tons sold, development costs absorbed by the coal revenue generated during development, costs incurred to purchase third-party metallurgical coal to blend with Itmann coal, royalties and production taxes, hauling of raw coal and direct administration costs. The $57 million increase in operating costs - Itmann Mining Complex was primarily due to an increase in the volume of coal produced and purchased as the operations transitioned from development mining to the full production phase.

Operating costs - Terminal primarily consist of costs related to throughput tons at the CONSOL Marine Terminal. The $2 million increase was due to a significant increase in throughput tonnage. See “Operational Performance - CONSOL Marine Terminal Analysis” for further information on segment operating costs.

Coal reserve holding costs increased $6 million in the period-to-period comparison, primarily as a result of the termination/expiration of various coal leases during the year ended December 31, 2023.

Employee-related legacy liability expense increased $5 million in the period-to-period comparison primarily due to the impact of changes in actuarial assumptions made at the beginning of each year. See Note 15 - Pension and Other Postretirement Benefits Plans and Note 16 - Coal Workers' Pneumoconiosis and Workers' Compensation in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Depreciation, Depletion, and Amortization

On a consolidated basis, depreciation, depletion and amortization costs were $241 million for the year ended December 31, 2023, compared to $227 million for the year ended December 31, 2022. Approximately $6 million of the increase in depreciation, depletion and amortization in the period-to-period comparison was due to the commissioning of the Itmann Preparation Plant and the transition from development mining to the production phase in late 2022. Approximately $5 million of the increase was attributable to current year adjustments to the Company's asset retirement obligations based on current projected cash outflows. The remaining $3 million of the increase was due to various other assets placed in service during the current year, none of which were individually significant.

General and Administrative Costs

On a consolidated basis, general and administrative costs were $103 million for the year ended December 31, 2023, compared to $117 million for the year ended December 31, 2022. The $14 million decrease in the period-to-period comparison was primarily related to decreased expense under the long-term incentive compensation plan incurred in the year ended December 31, 2023 compared to the year ended December 31, 2022, primarily due to fluctuations in the Company's share price and vesting periods during each of the respective periods.

Interest Expense

On a consolidated basis, interest expense, net of amounts capitalized, was $29 million for the year ended December 31, 2023, compared to $53 million for the year ended December 31, 2022. The decrease in the period-to-period comparison was primarily due to less debt outstanding as the Company continued its de-leveraging efforts.

Operational Performance: Year Ended December 31, 2023 Compared with the Year Ended December 31, 2022

CONSOL Energy presently consists of two reportable segments, the PAMC and the CONSOL Marine Terminal. The PAMC includes the Bailey Mine, the Enlow Fork Mine, the Harvey Mine and a centralized preparation plant. The PAMC segment's principal activities include the mining, preparation and marketing of bituminous coal, sold primarily to industrial end-users, metallurgical end-users and power generators. The segment also includes general and administrative activities and interest expense, as well as various other activities assigned to the PAMC segment, but not included in the cost components on a per unit basis. The CONSOL Marine Terminal segment provides coal export terminal services through the Port of Baltimore. The segment also includes general and administrative activities and interest expense, as well as various other activities assigned to the CONSOL Marine Terminal segment.

The Company evaluates the performance of its segments utilizing Adjusted EBITDA and various sales and production metrics. Adjusted EBITDA measures the operating performance of the Company's segments and is used to allocate resources to the Company's segments. The following table presents results by reportable segment for each of the periods indicated.

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	Year Ended December 31,
	2023		2022		Variance
PAMC
Total Tons Produced (in millions)	26.1		23.9		2.2
Total Tons Sold (in millions)	26.0		24.1		1.9
Average Realized Coal Revenue per Ton Sold(1)	$	77.74	$	69.89	$	7.85
Average Cash Cost of Coal Sold per Ton(1)	$	36.10	$	34.56	$	1.54
Average Cash Margin per Ton Sold(1)	$	41.64	$	35.33	$	6.31
Adjusted EBITDA (in thousands)(1)	$	1,019,161	$	773,095	$	246,066

CONSOL Marine Terminal
Throughput Tons (in millions)	19.0		13.7		5.3
Adjusted EBITDA (in thousands)(1)	$	80,322	$	52,259	$	28,063

(1) Adjusted EBITDA is a non-GAAP financial measure, and average realized coal revenue per ton sold, average cash cost of coal sold per ton and average cash margin per ton sold are operating ratios derived from non-GAAP financial measures. See “How We Evaluate Our Operations - Reconciliation of Non-GAAP Financial Measures” above for an explanation and reconciliation of these amounts to the nearest GAAP measures.

PAMC ANALYSIS:

Coal Production

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


	Year Ended December 31,
Mine	2023	2022	Variance
Bailey	11,164	11,568	(404)
Enlow Fork	8,661	6,292	2,369
Harvey	6,237	6,075	162
Total	26,062	23,935	2,127

Coal production was 26.1 million tons for the year ended December 31, 2023, compared to 23.9 million tons for the year ended December 31, 2022. The PAMC's coal production increased in the period-to-period comparison primarily due to the completion of development of the Company's fifth longwall at the PAMC toward the end of the fourth quarter of 2022.

Coal Operations

Adjusted EBITDA for the year ended December 31, 2023 was $1,019 million, compared to $773 million for the year ended December 31, 2022. The improvement was primarily attributable to a $7.85 increase in average realized coal revenue per ton sold, as well as a 1.9 million ton increase in tons sold, partially offset by a $1.54 increase in the average cash cost of coal sold per ton. The increase in average realized coal revenue per ton sold is directly attributable to the Company's strong contracted position and flexibility to place its coal sales into the export market that has yielded a better arbitrage for its product than the domestic market. Specifically in the domestic market, the carryover effect of mild winter weather during the first quarter of 2023, which contributed to increased power plant coal stockpiles and natural gas inventory build, with corresponding softening in coal, natural gas and power prices, led to softer than normal demand for coal-fired electricity generation during the remainder of 2023. As a result, the Company continued its pivot away from the domestic market and into stronger export markets. The Company's realized coal revenue for the year ended December 31, 2022 was also impacted by the settlement of certain commodity derivatives at a loss of $289 million. All of the Company's commodity derivatives were settled as of December 31, 2022 (see Note 21 - Derivatives in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The increase in the average cash cost of coal sold per ton was primarily due to persistent inflationary pressures on supplies, maintenance costs and contractor labor costs compared to the prior-year period.

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CONSOL MARINE TERMINAL ANALYSIS:

Adjusted EBITDA for the year ended December 31, 2023 was $80 million, compared to $52 million for the year ended December 31, 2022. Throughput volumes at the CONSOL Marine Terminal were 19.0 million tons for the year ended December 31, 2023, compared to 13.7 million tons for the year ended December 31, 2022. CONSOL Marine Terminal revenue was $106 million for the year ended December 31, 2023 compared to $79 million for the year ended December 31, 2022, due to the significantly increased throughput tonnage, which was primarily a result of the shift of PAMC coal sales into the export market.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. See Note 1 - Significant Accounting Policies in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. CONSOL Energy bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates on an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Asset Retirement Obligations

The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current coal mine disturbance and final coal mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of the Company's total asset retirement obligations, which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $241 million at December 31, 2023. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

Accounting for asset retirement obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For active locations, the present value of the estimated asset retirement obligations is capitalized as part of the carrying amount of the long-lived asset. For locations that have been fully depleted or closed, the present value of a change in the estimated value of the obligation is recorded directly to the consolidated statements of income. Asset retirement obligations primarily relate to the reclamation of land upon mine closure, the treatment of mine water discharge where necessary, and the plugging of gas wells acquired for mining purposes. Changes in the assumptions used to calculate the liabilities can have a significant effect on the asset retirement obligations. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future expenditures, estimated mine lives, assumptions involving inflation rates and the assumed credit-adjusted risk-free interest rate.

Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement obligation and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas accretion will be recognized until the reclamation obligations are satisfied.

The Company believes that the accounting estimates related to asset retirement obligations are “critical accounting estimates” because the Company must assess the expected amount and timing of asset retirement obligations. In addition, the Company must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Income Taxes

Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2023, CONSOL Energy had deferred tax liabilities in excess of deferred tax assets of approximately $36 million.

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CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis, that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that CONSOL Energy believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. At December 31, 2023 and 2022, CONSOL Energy had liabilities for uncertain tax positions of $2 million recorded in Other Accrued Liabilities and Deferred Income Taxes.

The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment regarding the amount of financial statement benefit to record for uncertain tax positions. When evaluating whether or not a valuation allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies, reversal of deferred tax assets and liabilities and forecasted future taxable income. In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. At December 31, 2023 and 2022, no valuation allowance was recorded.

Impairment of Long-Lived Assets

CONSOL Energy reviews the carrying value of its long-lived assets whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Long-lived assets are not reviewed for impairment unless an impairment indicator is noted. Examples of impairment indicators include:

•a significant decrease in the market price of a long-lived asset;

•a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition;

•a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset, including an adverse action of assessment by a regulator;

•an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

•a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; or

•a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The term more likely than not refers to a level of likelihood that is more than 50 percent.

The above factors are not all inclusive, and management routinely evaluates whether impairment indicators are present. If one or more of the above events or changes in circumstances occur, CONSOL Energy performs a recoverability test, which compares the projected undiscounted cash flows from the use and eventual disposition of a long-lived asset or asset group to its carrying value. Individual assets are grouped for impairment review purposes based on the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets. If the carrying value of a long-lived asset exceeds the future undiscounted cash flows expected from the asset, the amount of impairment recorded is measured as the difference between the asset's carrying value and the estimated fair value of the asset, determined using discounted future cash flows. The fair value of impaired assets is typically determined based on various factors, including the present values of expected future cash flows using a risk-adjusted discount rate, the marketability of coal properties and the estimated fair value of assets that could be sold or used at other operations.

Assumptions about sales, operating margins, capital expenditures and sales prices are based on the Company's forecasts, business plans, economic projections, and anticipated future cash flows. No indicators of impairment were present and, therefore, no impairment losses were recorded during the years ended December 31, 2023, 2022 and 2021.

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Liquidity and Capital Resources

CONSOL Energy's potential sources of liquidity include cash generated from operations, cash on hand, short-term investments of U.S. Treasury securities, borrowings under the revolving credit facility and securitization facility (which are discussed below), and, if necessary, the ability to issue additional equity or debt securities. The Company believes that cash generated from these sources, without needing to issue additional equity or debt securities, will be sufficient to meet its short-term working capital requirements, long-term capital expenditure requirements, and debt servicing obligations, as well as to provide required letters of credit.

During the second quarter of 2023, the Company amended its revolving credit facility to achieve additional financial flexibility by increasing the capacity of the facility and easing certain restrictive covenants, specifically around investments and shareholder returns. These covenants have been simplified to better align with the significantly improved credit profile of the business and are now leverage and liquidity-based moving forward. The Company was successful in securing incremental commitments in the amount of $95 million, which includes commitments from multiple new lenders to the facility and upsized commitments from 60% of existing lenders. The revolving credit facility now has a borrowing capacity of $355 million and provides for the Company's ability to increase the revolving commitments or issue term loans in an additional amount not to exceed $45 million and up to an aggregate total amount of $400 million.

Pricing for the Company's coal remained elevated compared to historical norms. These higher prices are bolstering the Company's cash flows, which has allowed the Company to accelerate debt reduction and shareholder return objectives. As a result, interest expense and debt servicing costs are declining. These factors allow the Company to continue to opportunistically reduce its debt levels and/or return capital to stockholders in the form of stock repurchases and/or dividends. During the year ended December 31, 2023, the Company generated cash flows from operating activities of approximately $858 million and utilized a portion of operating cash flows to retire outstanding indebtedness. More specifically, the Company made debt repayments of $99 million to fully retire its Second Lien Notes (as defined below), $64 million to payoff its Term Loan B Facility, and $26 million on its equipment-financed and other debt. Our total liquidity as of December 31, 2023 was comprised of the following:


(in millions)	December 31, 2023
Cash and Cash Equivalents	$	199
Short-Term Investments	82
	281
Revolving Credit Facility - Current Availability	355
Less: Letters of Credit Outstanding	(111)
Total Liquidity	$	525

Events that negatively impact our overall financial condition and liquidity could result in our inability to comply with our credit facility's financial covenants. This could limit our access to our credit facilities if we are unable to obtain waivers from our lenders or amend the credit facilities. Additionally, access to capital remains challenging for the Company's industry as a result of banking, institutional and investor environmental, social and governance (ESG) requirements and limitations, which tend to discourage investment in coal and other fossil fuel companies. However, the Company expects to maintain adequate liquidity through its operating cash flow, cash and cash equivalents on hand, and short-term investments, as well as its revolving credit facility and securitization facility, to fund its working capital and capital expenditures in the short-term and long-term.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. These risks include a reduction of our ability to raise capital in the equity markets, less availability and higher costs of additional credit and potential counterparty defaults. Overall market disruptions, including as a result of recent or additional bank failures, rising interest rates and sustained high inflation, may impact the Company's collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security.

Over the past few years, the insurance and surety markets have been increasingly challenging, particularly for coal companies. We have experienced rising premiums, reduced coverage and/or fewer providers willing to underwrite policies and surety bonds. Terms have generally become more unfavorable, including increases in the amount of collateral required to secure surety bonds. However, more recently, we have seen insurance rates stabilize and even decrease on certain lines of coverage, as new insurance carriers have entered the market. Further cost burdens on our ability to maintain adequate insurance and bond coverage may adversely impact our operations, financial position and liquidity.

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CONSOL Energy participates in the United Mine Workers of America (the “UMWA”) Combined Benefit Fund and the UMWA 1992 Benefit Plan for which benefits are reflected in the Company's consolidated financial statements when paid. These benefit arrangements may result in additional liabilities that are not recognized on the Consolidated Balance Sheet at December 31, 2023. The various multi-employer benefit plans are discussed in Note 17—Other Employee Benefit Plans in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. CONSOL Energy's total contributions under the Coal Industry Retiree Health Benefit Act of 1992 were $4 million and $4 million for the years ended December 31, 2023 and 2022, respectively. Based on available information at December 31, 2023, CONSOL Energy's aggregate obligation for the UMWA Combined Benefit Fund and 1992 Benefit Plan is estimated to be approximately $33 million. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure its financial obligations for employee-related, environmental, performance and various other items which are not reflected on the Consolidated Balance Sheet at December 31, 2023. Management believes these items will expire without being funded. See Note 23—Commitments and Contingent Liabilities in the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Cash Flows (in millions)


	For the Years Ended December 31,
	2023		2022		Change
Cash Provided by Operating Activities	$	858	$	651	$	207
Cash Used in Investing Activities	$	(259)	$	(142)	$	(117)
Cash Used in Financing Activities	$	(682)	$	(380)	$	(302)

Cash provided by operating activities increased $207 million in the period-to-period comparison, primarily due to a $241 million increase in adjusted EBITDA, a non-GAAP financial measure, offset by other working capital changes that occurred throughout both periods.

Cash used in investing activities increased $117 million in the period-to-period comparison, primarily due to a net investment of $78 million into U.S. Treasury securities during the year ended December 31, 2023. Capital expenditures decreased $4 million primarily due to the completion of construction of the Itmann preparation plant, which was commissioned during the third quarter of 2022, partially offset by an increase in equipment-related expenditures and expenditures associated with the solid waste disposal project at the PAMC. The remaining variance within investing cash flows is related to the timing and magnitude of asset sales and other investing activity. The Company's capital expenditures are set forth below.


	For the Years Ended December 31,
	2023		2022		Change
Equipment Purchases and Rebuilds	$	76	$	43	$	33
Building and Infrastructure	55		97		(42)
Solid Waste Disposal Project	27		15		12
IS&T Infrastructure	1		2		(1)
Other	9		15		(6)
Total Capital Expenditures	$	168	$	172	$	(4)

Cash flows used in financing activities increased $302 million in the period-to-period comparison primarily driven by $399 million in cash outflow during the year ended December 31, 2023 related to CONSOL Energy share repurchases. This increase was partially offset by a $103 million decrease in net payments on indebtedness in the period-to-period comparison primarily due to the payoff of the Term Loan A and Term Loan B Facilities in June 2022 and June 2023, respectively. However, this was partially offset by an increase in payments in the period-to-period comparison to fully redeem the remaining balance of the Company's Second Lien Notes in July 2023.

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Revolving Credit Facility

In November 2017, CONSOL Energy entered into a revolving credit facility with PNC Bank, N.A. (the “Revolving Credit Facility”). The Revolving Credit Facility has been amended several times, the most recent of which occurred in June 2023. This amendment increased the available revolving commitments from $260 million to $355 million and provides for the Company's ability to increase the revolving commitments or issue term loans in an additional amount not to exceed $45 million and up to an aggregate total amount of $400 million. The maturity date of the Revolving Credit Facility is July 18, 2026.

Borrowings under the Company's Revolving Credit Facility bear interest at a floating rate that is, at the Company's option, either (i) SOFR plus the applicable SOFR adjustment (as defined therein) depending on the applicable interest period plus an applicable margin or (ii) an alternate base rate plus an applicable margin. The applicable margin for the Revolving Credit Facility depends on the total net leverage ratio. Obligations under the Revolving Credit Facility are guaranteed by (i) all owners of the PAMC held by the Company, (ii) any other members of the Company’s group that own any portion of the collateral securing the Revolving Credit Facility, and (iii) subject to certain customary exceptions and agreed materiality thresholds, all other existing or future direct or indirect wholly-owned restricted subsidiaries of the Company. The obligations are secured by, subject to certain exceptions (including a limitation of pledges of equity interests in certain subsidiaries and certain thresholds with respect to real property), a first-priority lien on (i) the Company’s interest in the Pennsylvania Mining Complex, (ii) the equity interests in PA Mining Complex LP held by the Company, (iii) the CONSOL Marine Terminal, (iv) the Itmann Mining Complex, and (v) the 1.3 billion tons of Greenfield Reserves and Resources.

The Revolving Credit Facility also includes financial covenants, including (i) a maximum first lien gross leverage ratio, (ii) a maximum total net leverage ratio, and (iii) a minimum fixed charge coverage ratio. The maximum first lien gross leverage ratio is calculated as the ratio of Consolidated First Lien Debt to Consolidated EBITDA. Consolidated EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, nonrecurring transaction expenses, extraordinary gains and losses, gains and losses on discontinued operations and gains and losses on debt extinguishment. The maximum total net leverage ratio is calculated as the ratio of Consolidated Indebtedness, minus Cash on Hand, to Consolidated EBITDA. The minimum fixed charge coverage ratio is calculated as the ratio of Consolidated EBITDA to Consolidated Fixed Charges. Consolidated Fixed Charges, as used in the covenant calculation, include cash interest payments, cash payments for income taxes, scheduled debt repayments, Maintenance Capital Expenditures and cash payments related to legacy employee liabilities to the extent in excess of amounts accrued in the calculation of Consolidated EBITDA. Under the Revolving Credit Facility, the maximum first lien gross leverage ratio shall be 1.50 to 1.00, the maximum total net leverage ratio shall be 2.50 to 1.00 and the minimum fixed charge coverage ratio shall be 1.10 to 1.00.

The Company's first lien gross leverage ratio was 0.01 to 1.00 at December 31, 2023. The Company's total net leverage ratio was (0.08) to 1.00 at December 31, 2023. The Company's fixed charge coverage ratio was 3.42 to 1.00 at December 31, 2023. Accordingly, the Company was in compliance with all of its financial covenants under the Revolving Credit Facility as of December 31, 2023.

The Revolving Credit Facility contains customary events of default, including with respect to a failure to make payments when due, cross-default and cross-judgment default and certain bankruptcy and insolvency events.

At December 31, 2023, there were no borrowings outstanding under the Revolving Credit Facility and the facility is currently only used for providing letters of credit, with $111 million of letters of credit outstanding, leaving $244 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CONSOL Energy sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

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Securitization Facility

At December 31, 2023, CONSOL Energy and certain of its U.S. subsidiaries are parties to a trade accounts receivable securitization facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. In July 2022, the securitization facility was amended to, among other things, extend the maturity date to July 29, 2025.

Pursuant to the securitization facility, CONSOL Thermal Holdings LLC, an indirect, wholly-owned subsidiary of the Company, sells trade receivables to CONSOL Pennsylvania Coal Company LLC, a wholly-owned subsidiary of the Company. CONSOL Marine Terminals LLC, a wholly-owned subsidiary of the Company, and CONSOL Pennsylvania Coal Company LLC sell and/or contribute trade receivables (including receivables sold to CONSOL Pennsylvania Coal Company LLC by CONSOL Thermal Holdings LLC) to CONSOL Funding LLC, a wholly-owned subsidiary of the Company (the “SPV”). The SPV, in turn, pledges its interests in the receivables to PNC Bank, N.A., which either makes loans or issues letters of credit on behalf of the SPV. The maximum amount of advances and letters of credit outstanding under the securitization facility may not exceed $100 million.

Loans under the securitization facility accrue interest at a reserve-adjusted market index rate equal to the applicable term SOFR rate. Loans and letters of credit under the securitization facility also accrue a program fee and a letter of credit participation fee, respectively, ranging from 2.00% to 2.50% per annum depending on the total net leverage ratio of CONSOL Energy. In addition, the SPV paid certain structuring fees to PNC Capital Markets LLC and pays other customary fees to the lenders, including a fee on unused commitments equal to 0.60% per annum.

The agreements comprising the securitization facility contain various customary representations and warranties, covenants and default provisions which provide for the termination and acceleration of the commitments and loans under the securitization facility in certain circumstances including, but not limited to, failure to make payments when due, breach of representation, warranty or covenant, certain insolvency events or failure to maintain the security interest in the trade receivables, and defaults under other material indebtedness. CONSOL Energy guarantees the performance of the obligations of CONSOL Thermal Holdings LLC, CONSOL Marine Terminals LLC and CONSOL Pennsylvania Coal Company LLC under the securitization, and will guarantee the obligations of any additional originators or successor servicer that may become party to the securitization. However, neither CONSOL Energy nor its affiliates will guarantee collectability of receivables or the creditworthiness of obligors thereunder.

At December 31, 2023, eligible accounts receivable yielded $72 million of borrowing capacity. At December 31, 2023, the facility had no outstanding borrowings and approximately $72 million of letters of credit outstanding, leaving $38 thousand of unused capacity. Costs associated with the receivables facility were $1 million for the year ended December 31, 2023. The Company has not derecognized any receivables due to its continued involvement in the collections efforts.

11.00% Senior Secured Second Lien Notes due 2025

On November 13, 2017, the Company issued $300 million in aggregate principal amount of 11.00% Senior Secured Second Lien Notes due 2025 (the “Second Lien Notes”) pursuant to an indenture (the “Indenture”) dated as of November 13, 2017, by and between the Company and UMB Bank, N.A., a national banking association, as trustee and collateral trustee (the “Trustee”). On November 28, 2017, certain subsidiaries of the Company executed a supplement to the Indenture and became party to the Indenture as a guarantor (the “Guarantors”). The Second Lien Notes were secured by second priority liens on substantially all of the assets of the Company and the Guarantors that are pledged on a first-priority basis as collateral securing the Company’s obligations under the Revolving Credit Facility (described above), subject to certain exceptions under the Indenture.

During the year ended December 31, 2023, the Company fully redeemed the remaining outstanding balance of its Second Lien Notes at a redemption price of 102.75% of the stated principal outstanding in the amount of $99 million.

The Indenture contained covenants that limited the ability of the Company and the Guarantors, to (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) create liens to secure indebtedness; (iii) declare or pay dividends on the Company’s common stock, redeem stock or make other distributions to the Company’s stockholders; (iv) make investments; (v) pay or make dividends, loans or other asset transfers from the Company’s restricted subsidiaries; (vi) merge or consolidate, or sell, transfer, lease or dispose of substantially all of the Company’s assets; (vii) sell or otherwise dispose of certain assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants were subject to important exceptions and qualifications. If the Second Lien Notes achieved an investment grade rating from both Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc. and no default under the Indenture existed, many of the foregoing covenants would have terminated and ceased to apply. The Indenture also contained customary events of default.

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Pennsylvania Economic Development Financing Authority Bonds

In April 2021, CONSOL Energy borrowed the proceeds received from the sale of tax-exempt bonds issued by PEDFA in an aggregate principal amount of $75 million (the “PEDFA Bonds”). The PEDFA Bonds bear interest at a fixed rate of 9.00% for an initial term of seven years. The PEDFA Bonds mature on April 1, 2051 but are subject to mandatory purchase by the Company on April 13, 2028, at the expiration of the initial term rate period. The PEDFA Bonds were issued pursuant to an indenture (the “PEDFA Indenture”) dated as of April 1, 2021, by and between PEDFA and Wilmington Trust, N.A., a national banking association, as trustee (the “PEDFA Notes Trustee”). PEDFA made a loan of the proceeds of the PEDFA Bonds to the Company pursuant to a Loan Agreement (the “Loan Agreement”) dated as of April 1, 2021 between PEDFA and the Company. Under the terms of the Loan Agreement, the Company agreed to make all payments of principal, interest and other amounts at any time due on the PEDFA Bonds or under the PEDFA Indenture. PEDFA assigned its rights as lender under the Loan Agreement, excluding certain reserved rights, to the PEDFA Notes Trustee. Certain subsidiaries of the Company (the “PEDFA Notes Guarantors”) executed a Guaranty Agreement (the “Guaranty”) dated as of April 1, 2021 in favor of the PEDFA Notes Trustee, guarantying the obligations of the Company under the Loan Agreement to pay the PEDFA Bonds when and as due. The obligations of the Company under the Loan Agreement and of the PEDFA Notes Guarantors under the Guaranty are secured by second priority liens on substantially all of the assets of the Company and the PEDFA Notes Guarantors. The Loan Agreement and Guaranty incorporate by reference covenants in the Indenture under which the Second Lien Notes were issued (discussed previously).

Material Cash Requirements

CONSOL Energy expects to make payments of $14 million on its long-term debt obligations, including interest, in the next 12 months. Refer to Note 13 – Long-Term Debt for additional information concerning material cash requirements in future years.

CONSOL Energy expects to make payments of $16 million on its operating and finance lease obligations, including interest, in the next 12 months. Refer to Note 14 – Leases for additional information concerning material cash requirements in future years.

CONSOL Energy expects to make payments of $49 million on its employee-related long-term liabilities in the next 12 months. Refer to Note 15 – Pension and Other Postretirement Benefit Plans and Note 16 – Coal Workers’ Pneumoconiosis and Workers’ Compensation for additional information concerning material cash requirements in future years.

CONSOL Energy believes it will be able to satisfy these material requirements with cash generated from operations, cash on hand, short-term investments, borrowings under the revolving credit facility and securitization facility, and, if necessary, cash generated from its ability to issue additional equity or debt securities.

Debt

At December 31, 2023, CONSOL Energy had total long-term debt and finance lease obligations of $199 million outstanding, including the current portion of $11 million. This long-term debt consisted of:

•An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the CONSOL Marine Terminal, which bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes is guaranteed by CONSOL Energy.

•An aggregate principal amount of $75 million of PEDFA bonds, which were issued to finance the ongoing expansion of the coal refuse disposal area at the Central Preparation Plant, which bear interest at 9.00% per annum for an initial term of seven years and mature in April 2051. Interest on the PEDFA Bonds is payable on February 1 and August 1 of each year.

•An aggregate principal amount of $14 million of finance leases with a weighted average interest rate of 6.68%.

•Advanced royalty commitments of $6 million with a weighted average interest rate of 8.80% per annum.

•An aggregate principal amount of $1 million of other debt arrangements.

At December 31, 2023, CONSOL Energy had no borrowings outstanding and approximately $111 million of letters of credit outstanding under the $355 million senior secured Revolving Credit Facility. At December 31, 2023, CONSOL Energy had no borrowings outstanding and approximately $72 million of letters of credit outstanding under the $100 million securitization facility.

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Stock and Debt Repurchases

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 Second Lien Notes. Since the program's inception, the Company's Board of Directors has subsequently amended the program several times, the most recent of which amendment in April 2023 raised the aggregate limit of the Company's repurchase authority to $1 billion. The program expires on December 31, 2024.

Under the terms of the program, CONSOL Energy is permitted to make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs or in structured share repurchase programs. CONSOL Energy is also authorized to enter into one or more 10b5-1 plans with respect to any of the repurchases. Any repurchases of common stock or notes are to be funded from available cash on hand or short-term borrowings. The program does not obligate CONSOL Energy to acquire any particular amount of its common stock or notes, and the program can be modified or suspended at any time at the Company’s discretion. The program is conducted in compliance with applicable legal requirements imposed by any credit agreement, receivables purchase agreement or indenture.

During the year ended December 31, 2023, the Company did not make any open market repurchases of its Second Lien Notes in accordance with this program. During the year ended December 31, 2023, the Company repurchased and retired 5,224,016 shares of common stock at an average price of $75.69 per share.

Total Equity and Dividends

Total equity attributable to CONSOL Energy was $1,343 million at December 31, 2023 and $1,166 million at December 31, 2022. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.

The Company paid the following dividends during the year ended December 31, 2023:

Per Share

Total Paid (000s omitted)

Payment Timing

Shareholder of Record Date

$1.10

$38,287

February 28, 2023

February 17, 2023

$1.10

$37,187

May 23, 2023

May 15, 2023

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Recent Accounting Pronouncements

In December 2023, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-09 Income Taxes (Topic 740). The amendments in this Update address investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation, (2) provide additional information for reconciling items that meet a quantitative threshold (if the effect of those reconciling items is equal to or greater than 5 percent of the amount computed by multiplying pretax income [or loss] by the applicable statutory income tax rate), (3) disclose the amount of income taxes paid (net of refunds received) disaggregated by federal (national), state, and foreign taxes, (4) disclose the amount of income taxes paid (net of refunds received) disaggregated by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than 5 percent of total income taxes paid (net of refunds received), (5) disclose income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign, and (6) disclose income tax expense (or benefit) from continuing operations disaggregated by federal (national), state, and foreign. The amendments in this update are effective for annual periods beginning after December 15, 2024, and should be applied prospectively. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

In November 2023, the FASB issued ASU 2023-07 Segment Reporting (Topic 280). The amendments in this Update improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. Topic 280 requires a public entity to report a measure of segment profit or loss that the chief operating decision maker (CODM) uses to assess segment performance and make decisions about allocating resources. Topic 280 also requires other specified segment items and amounts, such as depreciation, amortization, and depletion expense, to be disclosed under certain circumstances. The amendments in this Update do not change or remove those disclosure requirements. The amendments in this Update also do not change how a public entity identifies its operating segments, aggregates those operating segments, or applies the quantitative thresholds to determine its reportable segments. The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 and should be applied retrospectively. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

In August 2023, the FASB issued ASU 2023-05 - Business Combinations—Joint Venture Formations (Subtopic 805-60). The amendments in this update address the accounting for contributions made to a joint venture, upon formation, in a joint venture's separate financial statements. The objectives of the amendments are to (1) provide decision-useful information to investors and other allocators of capital in a joint venture's financial statements and (2) reduce diversity in practice. The amendments in this update do not amend the definition of a joint venture, the accounting by an equity method investor for its investment in a joint venture, or the accounting by a joint venture for contributions received after its formation. The amendments in this update are effective prospectively for all joint venture formations with a formation date on or after January 1, 2025. Existing joint ventures may elect to apply the guidance retrospectively. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

In March 2023, the FASB issued ASU 2023-02 - Investments—Equity Method and Joint Ventures (Topic 323). The amendments in this update permit reporting entities to elect to account for their tax equity investments, regardless of the tax credit program from which the income tax credits are received, using the proportional amortization method if certain conditions are met. The amendments in this update apply to all reporting entities that hold (1) tax equity investments that meet the conditions for and elect to account for them using the proportional amortization method or (2) an investment in a low-income-housing tax credit (LIHTC) structure through a limited liability entity that is not accounted for using the proportional amortization method and to which certain LIHTC-specific guidance removed from Subtopic 323-740, Investments—Equity Method and Joint Ventures—Income Taxes, has been applied. The amendments in this update are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding the Company's exposure to the risks related to changes in commodity prices, interest rates and foreign exchange rates.

Commodity Price Risk

CONSOL Energy is exposed to market price risk in the normal course of selling coal. CONSOL Energy sells coal in the spot market and under both short-term and multi-year contracts that may contain prices subject to pre-established price adjustments that reflect (i) variances in the quality characteristics of coal delivered to the customer beyond threshold quality characteristics specified in the applicable sales contract, (ii) the actual calorific value of coal delivered to the customer, (iii) changes in electric power prices in the markets in which the Company's customers operate, as adjusted for any factors set forth in the applicable contract, and/or (iv) changes in published indices. CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base.

The Company's primary method of mitigating commodity price volatility is through short-term and multi-year fixed-price contracts. During 2021, the Company initiated a targeted commodity price hedging strategy to mitigate pricing volatility inherent in a portion of the Company’s 2022 physical contracts, related to variable pricing and the Company’s spot export business, and secure future cash flows for export sales. The commodity market volatility increased as demonstrated by significant market pricing increases throughout 2022. Loss on Commodity Derivatives, net during the year ended December 31, 2022 was $237 million. All of our hedging arrangements have been settled as of December 31, 2022, and no additional arrangements have been executed.

Interest Rate Risk

At December 31, 2023, CONSOL Energy's aggregate principal amount of debt outstanding is predominantly under fixed-rate instruments, and only $2 million of outstanding debt is subject to interest rate sensitivity.

Foreign Exchange Rate Risk

All of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, any fluctuations in currency exchange rates would have no impact to the Company's current financial transactions. However, because coal is sold internationally in U.S. dollars, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide the Company's international competitors with a competitive advantage. If CONSOL Energy's competitors' currencies decline against the U.S. dollar or against the Company's international customers' local currencies, those competitors may be able to offer lower prices for coal to the Company's customers on an exchanged adjusted basis. Furthermore, if the currencies of CONSOL Energy's overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal the Company sells to them. Consequently, currency fluctuations could adversely affect the competitiveness of CONSOL Energy's coal in international markets.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


			Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)			74
Consolidated Statements of Income for the Years Ended December 31, 2023, 2022 and 2021			76
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021			77
Consolidated Balance Sheets at December 31, 2023 and 2022			78
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2023, 2022 and 2021			80
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021			81
Notes to the Audited Consolidated Financial Statements			82

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of CONSOL Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 9, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosures to which it relates.

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						Asset Retirement Obligations - Closed Mines

Description of the Matter						CONSOL Energy accrues for the costs of current coal mine disturbance and final coal mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of the Company’s asset retirement obligations are based upon permit requirements and CONSOL Energy’s assessment of these requirements. The total asset retirement obligations, including the current portion, were approximately $241 million at December 31, 2023. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from the assumptions used in estimating the obligation or if governmental regulations change significantly. As discussed in Note 1 and Note 8 of the consolidated financial statements, the Company’s accounting for asset retirement obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For active locations, the present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For locations that have been fully depleted, or closed, the present value of a change in the estimated value of the obligation is recorded directly to the consolidated statements of income. Auditing the amounts recorded for closed-mine asset retirement obligations is complex and judgmental due to the estimation that is required to determine the value of the asset retirement obligation associated with closed mines. In particular, the estimation of the value of the asset retirement obligation is dependent upon a number of factors, including the estimated future expenditures, estimated mine life, inflation rates and the assumed credit-adjusted risk-free interest rate.

How We Addressed the Matter in Our Audit						We tested controls that address the risk of material misstatement relating to the measurement of the closed-mine asset retirement obligation. For example, we tested controls over management’s review of the estimates of asset retirement obligations for closed mines, management’s review over the timing and amount of expected asset retirement costs and management’s review over the assumptions discussed above. To test the closed-mine asset retirement obligation, our audit procedures included, among others, assessing the methodology used, testing the significant assumptions discussed above and testing the underlying data used by the Company in its analyses. We compared the assumptions used in developing the inflation rate and credit-adjusted risk-free rate used by management to historical trends, published reports and publicly available information. We compared the expected amounts and timing of future expenditures to historical data and evaluated the changes in those amounts. For example, we evaluated management’s methodology for determining the amount and timing of asset retirement obligation costs which is utilized to measure the asset retirement obligation, to current year activity, published pricing data and historical amounts. In addition, we involved our specialist to assist in our evaluation of management’s estimates of the closed mine asset retirement obligation, including review of assumptions, regulatory requirements, reclamation plans, estimated future expenditures, and engineering drawings for consistency with permit requirements. We also tested the completeness and accuracy of the data used in the estimation of the Company’s asset retirement obligations related to closed mines.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 2017.

Pittsburgh, Pennsylvania

February 9, 2024

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2023		2022		2021
Revenue and Other Income:
Coal Revenue	$	2,106,366	$	2,018,662	$	1,092,022
Terminal Revenue	106,166		78,915		65,193
Freight Revenue	294,103		182,441		103,819
Loss on Commodity Derivatives, net	—		(237,024)		(52,204)
Miscellaneous Other Income (Note 3)	53,261		24,354		38,394
Gain on Sale of Assets	8,981		34,589		11,723
Total Revenue and Other Income	2,568,877		2,101,937		1,258,947
Costs and Expenses:
Operating and Other Costs	1,120,065		949,222		745,292
Depreciation, Depletion and Amortization	241,317		226,878		224,583
Freight Expense	294,103		182,441		103,819
General and Administrative Costs	103,470		116,696		87,161
Loss (Gain) on Debt Extinguishment	2,725		5,623		(657)
Interest Expense	29,325		52,640		63,342
Total Costs and Expenses	1,791,005		1,533,500		1,223,540
Earnings Before Income Tax	777,872		568,437		35,407
Income Tax Expense (Note 5)	121,980		101,458		1,297
Net Income	$	655,892	$	466,979	$	34,110

Earnings per Share:
Total Basic Earnings per Share	$	19.91	$	13.41	$	0.99
Total Dilutive Earnings per Share	$	19.79	$	13.07	$	0.96

Dividends Declared per Common Share	$	2.20	$	2.05	$	—

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)


	For the Years Ended December 31,
	2023		2022		2021
Net Income	$	655,892	$	466,979	$	34,110
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments:
Amortization of Prior Service Credits (net of tax: $537, $561, $601)	(1,868)		(1,844)		(1,804)
Recognized Net Actuarial (Gain) Loss (net of tax: $512, $(2,459), $(5,122))	(1,782)		8,076		15,374
Settlement Loss Recognized (net of tax: $—, $—, $(6))	—		—		16
Other Comprehensive Gain before Reclassifications (net of tax: $(1,232), $(30,516), $(21,979))	4,150		99,164		65,617
Available-for-Sale Securities:
Unrealized Gain on Investments in Available-for-Sale Securities (net of tax: $23, $—, $—)	80		—		—
Derivative Instruments:
Unrealized Gain on Cash Flow Hedges (net of tax: $—, $116, $596)	—		401		1,721
Other Comprehensive Income	580		105,797		80,924

Comprehensive Income	$	656,472	$	572,776	$	115,034

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)


	December 31, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and Cash Equivalents	$	199,371	$	273,070
Short-Term Investments (Note 6)	81,932		—
Accounts and Notes Receivable
Trade Receivables, net	147,612		158,127
Other Receivables, net	12,765		38,517
Inventories (Note 9)	88,154		66,290
Other Current Assets	71,172		62,479
Total Current Assets	601,006		598,483
Property, Plant and Equipment (Note 10):
Property, Plant and Equipment	5,552,404		5,408,577
Less—Accumulated Depreciation, Depletion and Amortization	3,649,281		3,448,495
Total Property, Plant and Equipment—Net	1,903,123		1,960,082
Other Assets:

Right of Use Asset - Operating Leases (Note 14)	14,658		19,799
Salary Retirement (Note 15)	47,246		38,548
Other Noncurrent Assets, net	108,970		87,465
Total Other Assets	170,874		145,812
TOTAL ASSETS	$	2,675,003	$	2,704,377

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)


	December 31, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	137,243	$	130,232
Current Portion of Long-Term Debt (Note 13)	11,106		28,846
Operating Lease Liability, Current Portion (Note 14)	4,769		4,922
Commodity Derivatives (Note 21)	—		15,142
Other Accrued Liabilities (Note 12)	290,606		269,656
Total Current Liabilities	443,724		448,798
Long-Term Debt:
Long-Term Debt (Note 13)	181,885		342,110
Finance Lease Obligations (Note 14)	4,182		13,225
Total Long-Term Debt	186,067		355,335
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions (Note 15)	207,908		232,593
Pneumoconiosis Benefits (Note 16)	154,943		148,390
Asset Retirement Obligations (Note 8)	212,621		221,858
Workers’ Compensation (Note 16)	39,144		40,951
Salary Retirement (Note 15)	20,808		20,585
Operating Lease Liability (Note 14)	10,385		15,073
Deferred Income Taxes (Note 5)	36,219		21,914
Other Noncurrent Liabilities	19,742		33,054
Total Deferred Credits and Other Liabilities	701,770		734,418
TOTAL LIABILITIES	1,331,561		1,538,551
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 62,500,000 Shares Authorized, 29,910,439 Shares Issued and Outstanding at December 31, 2023; 34,746,904 Shares Issued and Outstanding at December 31, 2022	299		347
Capital in Excess of Par Value	547,861		646,237
Retained Earnings	944,342		668,882
Accumulated Other Comprehensive Loss	(149,060)		(149,640)
TOTAL EQUITY	1,343,442		1,165,826
TOTAL LIABILITIES AND EQUITY	$	2,675,003	$	2,704,377

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands)


	Common Stock		Capital in Excess of Par Value		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total Equity
December 31, 2020	$	340	$	642,887	$	246,850	$	(336,558)	$	553,519
Net Income	—		—		34,110		—		34,110
Actuarially Determined Long-Term Liability Adjustments (Net of $(26,506) Tax)	—		—		—		79,203		79,203
Interest Rate Hedge (Net of ($596) Tax)	—		—		—		1,721		1,721
Comprehensive Income	—		—		34,110		80,924		115,034
Issuance of Common Stock	5		(5)		—		—		—
Amortization of Stock-Based Compensation Awards	—		6,632		—		—		6,632
Shares Withheld for Taxes	—		(2,303)		—		—		(2,303)
CCR Merger	—		(266)		—		197		(69)
December 31, 2021	$	345	$	646,945	$	280,960	$	(255,437)	$	672,813
Net Income	—		—		466,979		—		466,979
Actuarially Determined Long-Term Liability Adjustments (Net of ($32,414) Tax)	—		—		—		105,396		105,396
Interest Rate Hedge (Net of ($116) Tax)	—		—		—		401		401
Comprehensive Income	—		—		466,979		105,797		572,776
Issuance of Common Stock	4		(4)		—		—		—
Repurchases of Common Stock (124,454 Shares)	(2)		(2,333)		(5,653)		—		(7,988)
Amortization of Stock-Based Compensation Awards	—		7,890		—		—		7,890
Shares Withheld for Taxes	—		(6,261)		—		—		(6,261)
Dividends on Common Shares ($2.05/share)	—		—		(71,486)		—		(71,486)
Dividend Equivalents Earned on Stock-Based Compensation Awards	—		—		(1,918)		—		(1,918)
December 31, 2022	$	347	$	646,237	$	668,882	$	(149,640)	$	1,165,826
Net Income	—		—		655,892		—		655,892
Actuarially Determined Long-Term Liability Adjustments (Net of ($183) Tax)	—		—		—		500		500
Investments in Available-for-Sale Securities (Net of $(23) Tax)	—		—		—		80		80
Comprehensive Income	—		—		655,892		580		656,472
Issuance of Common Stock	4		(4)		—		—		—
Repurchases of Common Stock (5,224,016 Shares)	(52)		(95,587)		(299,753)		—		(395,392)
Excise Tax on Repurchases of Common Stock	—		—		(3,729)		—		(3,729)
Amortization of Stock-Based Compensation Awards	—		10,046		—		—		10,046
Shares Withheld for Taxes	—		(12,831)		—		—		(12,831)
Dividends on Common Shares ($2.20/share)	—		—		(75,474)		—		(75,474)
Dividend Equivalents Earned on Stock-Based Compensation Awards	—		—		(1,476)		—		(1,476)
December 31, 2023	$	299	$	547,861	$	944,342	$	(149,060)	$	1,343,442

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)


	For the Years Ended December 31,
	2023		2022		2021
Cash Flows from Operating Activities:
Net Income	$	655,892	$	466,979	$	34,110
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	241,317		226,878		224,583
Stock-Based Compensation	10,046		7,890		6,632
Gain on Sale of Assets	(8,981)		(34,589)		(11,723)
Amortization of Debt Issuance Costs	5,468		8,314		8,552
Loss (Gain) on Debt Extinguishment	2,725		5,623		(657)
Deferred Income Taxes	14,121		49,387		(14,760)
Other Adjustments to Net Income	(3,418)		3,880		644
Changes in Operating Assets:
Trade and Other Receivables	36,922		(52,577)		44,707
Inventories	(21,540)		(3,020)		(6,676)
Other Current Assets	(4,673)		2,883		229
Changes in Other Assets	(11,725)		(26,063)		(13,797)
Changes in Operating Liabilities:
Accounts Payable	11,449		39,235		11,473
Commodity Derivatives, net Liability	(15,142)		(37,062)		52,204
Other Operating Liabilities	3,063		14,453		27,461
Changes in Other Liabilities	(57,575)		(21,221)		(57,413)
Net Cash Provided by Operating Activities	857,949		650,990		305,569
Cash Flows from Investing Activities:
Capital Expenditures	(167,791)		(171,506)		(132,752)
Proceeds from Sales of Assets	4,255		21,538		13,572
Investments in Mining-Related Activities	(7,481)		—		—
Proceeds from Sales of Short-Term Investments	122,658		—		—
Purchases of Short-Term Investments	(200,870)		—		—
Other Investing Activity	(10,203)		7,790		(8,181)
Net Cash Used in Investing Activities	(259,432)		(142,178)		(127,361)
Cash Flows from Financing Activities:
Payments on Finance Lease Obligations	(25,335)		(24,511)		(27,447)
Payments on Term Loan A	—		(41,250)		(25,000)
Payments on Term Loan B	(63,590)		(175,687)		(30,911)
Payments on Second Lien Notes	(101,832)		(52,074)		(17,092)
Proceeds from Long-Term Debt	—		—		75,000
Payments on Other Debt	(981)		(840)		(731)
Shares Withheld for Taxes	(12,831)		(6,261)		(2,303)
Repurchases of Common Stock	(399,379)		—		—
Debt Issuance and Financing Fees	(2,779)		(7,957)		(2,368)
Dividends	(75,474)		(71,486)		—
Net Cash Used in Financing Activities	(682,201)		(380,066)		(30,852)
Net (Decrease) Increase in Cash and Cash Equivalents and Restricted Cash	(83,684)		128,746		147,356
Cash and Cash Equivalents and Restricted Cash at Beginning of Period	326,952		198,206		50,850
Cash and Cash Equivalents and Restricted Cash at End of Period	$	243,268	$	326,952	$	198,206

The accompanying notes are an integral part of these financial statements.

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:

A summary of the significant accounting policies of CONSOL Energy Inc. and its subsidiaries (“we,” “our,” “us,” “our Company,” “the Company” and “CONSOL Energy”) is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.

Basis of Consolidation

The Consolidated Financial Statements include the accounts of CONSOL Energy Inc. and its wholly-owned and majority-owned and/or controlled subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.

Restricted Cash

Restricted cash includes the unused proceeds of tax-exempt bonds issued by the Pennsylvania Economic Development Financing Authority (“PEDFA”). Restricted cash also includes cash collateral supporting the Company's surety bond portfolio and letters of credit issued under the Company's accounts receivable securitization program. As of December 31, 2023, the Company had $43,897 in restricted cash. As of December 31, 2022, the Company had $53,882 in restricted cash.

Trade Receivables and Allowance for Credit Losses

Inventories

Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion, amortization and other related costs. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's coal operations.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost upon acquisition. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs that do not extend the useful lives of existing plant and equipment are expensed as incurred.

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Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine. Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. The Company employs this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Coal reserves are either owned in fee or controlled by lease. The duration of the leases vary; however, the lease terms are generally extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests. Depletion of leased coal interests is computed using the units-of-production method over recoverable coal reserves. The Company also makes advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and it makes payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. The Company evaluates its properties, including advance mining royalties and leased coal interests, for impairment indicators whenever events or circumstances indicate that the carrying amount may not be recoverable.

Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimated recoverable reserve tons assigned and accessible to the mine. Recoverable coal reserves are estimated on a clean coal ton equivalent, which excludes nonrecoverable coal reserves and anticipated central preparation plant processing refuse. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in Gain on Sale of Assets in the Consolidated Statements of Income.

Depreciation of plant and equipment is calculated using the straight-line method over the estimated useful lives or lease terms, generally as follows:


			Years
Buildings and improvements			10 to 45
Machinery and equipment			3 to 25
Leasehold improvements			Life of Lease

Capitalization of Interest

Interest costs associated with the development of significant properties and projects are capitalized until the project is substantially complete and ready for its intended use. A weighted average cost of borrowing rate is used. For the years ended December 31, 2023, 2022 and 2021, capitalized interest totaled $3,981, $5,425 and $2,425, respectively.

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Impairment of Long-lived Assets

Impairment of long-lived assets or asset groups is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' or asset groups' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. There were no indicators of impairment and, therefore, no impairment losses were recorded during the years ended December 31, 2023, 2022 and 2021.

Income Taxes

The Company files a consolidated federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes, exclusive of amounts recorded in Other Comprehensive Income (Loss). Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period.

Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizes a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Postretirement Benefits Other Than Pensions

Postretirement benefit obligations established by the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. Postretirement benefits other than pensions, except for those established pursuant to the Coal Act, are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification, which requires employers to accrue the cost of such retirement benefits for the employees' active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy administers these liabilities through a combination of self-insured and fully insured agreements. Differences between actual and expected results or changes in the value of obligations are recognized through Other Comprehensive Income (Loss).

Pneumoconiosis Benefits and Workers' Compensation

CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers' pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers' compensation benefits for employees who sustain employment-related physical injuries or some types of occupational disease. Workers' compensation benefits include compensation for disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.

Asset Retirement Obligations

Mine closing costs and costs associated with dismantling and removing de-gasification facilities are accrued using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For active locations, the present value of the estimated asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. For locations that have been fully depleted or closed, the present value of the change is recorded directly to the consolidated statements of income. Generally, the capitalized asset retirement obligation is depreciated on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and until the reclamation obligations are satisfied. Accretion is included in Depreciation, Depletion and Amortization on the Consolidated Statements of Income. Asset retirement

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obligations primarily relate to the closure of mines, which includes treatment of water and the reclamation of land upon exhaustion of coal reserves. Accrued mine closing costs, perpetual water treatment costs, reclamation and costs associated with dismantling and removing de-gasification facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements, in each case if and as applicable.

Subsidence

Subsidence occurs when there is sinking or shifting of the ground surface due to the removal of underlying coal. Areas affected may include, although are not limited to, streams, property, roads, pipelines and other land and surface structures. Total estimated subsidence claims are recognized in the period when the related coal has been extracted and are included in Operating and Other Costs on the Consolidated Statements of Income and Other Accrued Liabilities on the Consolidated Balance Sheets. On occasion, CONSOL Energy may elect to prepay for estimated damages prior to undermining the property, in return for a release of liability. Prepayments are included as assets and are either recognized as Other Current Assets or in Other Noncurrent Assets on the Consolidated Balance Sheets if the payment is made less than or greater than one year, respectively, prior to undermining the property.

Retirement Plans

CONSOL Energy has non-contributory defined benefit retirement plans. In 2015, CONSOL's qualified defined benefit retirement plan was frozen. The benefits for these plans are based primarily on years of service and employees' pay. These plans are accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The costs of these retiree benefits are recognized over the employees' service periods. CONSOL Energy uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income (Loss).

Stock-Based Compensation

Eligible CONSOL Energy employees participate in equity-based compensation plans. CONSOL Energy recognizes compensation expense for all stock-based compensation awards based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 18 - Stock-Based Compensation for additional information.

Revenue Recognition

Coal revenue is recognized when the performance obligation has been satisfied, and the corresponding transaction price has been determined. Generally, title passes when coal is loaded at the coal preparation facilities, at terminal locations or other customer destinations. The Company's coal contract revenue per ton is fixed or determinable based upon either fixed forward pricing or pricing derived from established indices and adjusted for nominal quality characteristics. Some coal contracts also contain positive electric power price-related adjustments, which represent market-driven price adjustments, in addition to a fixed base price per ton. The Company’s coal contracts generally do not allow for retroactive adjustments to pricing after title to the coal has passed and typically do not have significant financing components. See Note 2 - Revenue from Contracts with Customers for additional information.

Freight Revenue and Expense

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Contingencies

The Company is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

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Derivative Instruments

The Company may utilize derivative instruments to manage exposures to interest rate risk on long-term debt. The Company entered into interest rate swaps in order to achieve a mix of fixed and variable rate debt that it deemed appropriate. These interest rate swaps were designated as cash flow hedges of future variable interest payments and were accounted for as an asset or a liability in the accompanying Consolidated Balance Sheets at their fair value. The Company may, from time to time, also utilize derivative instruments to manage exposure to the risk of fluctuating coal prices related to forecasted or index-priced sales of coal or to the risk of changes in the fair value of a fixed price physical sales contract. The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market in order to manage its exposure to coal prices. The Company did not seek cash flow hedge accounting treatment for its commodity derivative financial instruments and therefore, changes in fair value were reflected in earnings throughout the terms of those instruments (see Note 21 - Derivatives and Note 22 - Fair Value of Financial Instruments for additional information).

In a cash flow hedge, the Company hedges the risk of changes in future cash flows related to the underlying item being hedged. Changes in the fair value of the derivative instrument used as a hedge instrument in a cash flow hedge are recorded in other comprehensive income or loss. Amounts in other comprehensive income or loss are reclassified to earnings when the hedged transaction affects earnings and are classified in a manner consistent with the transaction being hedged. The Company evaluates the effectiveness of its hedging relationships both at the hedge's inception and on an ongoing basis. Any ineffective portion of the change in fair value of a derivative instrument used as a hedge instrument in a cash flow hedge is recognized immediately in earnings.

Earnings per Share

Basic earnings per share are computed by dividing net income by the weighted average number of shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share, except that the weighted average number of shares outstanding is increased to include additional shares from restricted stock units and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding restricted stock units and performance share units were released, and that the proceeds from such activities, as applicable, were used to acquire shares of common stock at the average market price during the reporting period.

The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive:


	For the Years Ended December 31,
	2023	2022	2021
Anti-Dilutive Restricted Stock Units	1,146	942	45,653
Anti-Dilutive Performance Share Units	—	—	—
	1,146	942	45,653

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The computations for basic and dilutive earnings per share are as follows:


Dollars in thousands, except per share data	For the Years Ended December 31,
	2023		2022		2021
Numerator:
Net Income	$	655,892	$	466,979	$	34,110

Denominator:
Weighted-average shares of common stock outstanding	32,941,654		34,811,906		34,404,360
Effect of dilutive shares	200,353		906,349		984,198
Weighted-average diluted shares of common stock outstanding	33,142,007		35,718,255		35,388,558

Earnings per Share:
Basic	$	19.91	$	13.41	$	0.99
Dilutive	$	19.79	$	13.07	$	0.96

As of December 31, 2023, CONSOL Energy has 500,000 shares of preferred stock authorized, none of which are issued or outstanding.

Shares of common stock outstanding were as follows:


	2023	2022	2021
Balance, Beginning of Year	34,746,904	34,480,181	34,031,374
Retirement Related to Stock Repurchase (1)	(5,224,016)	(124,454)	—
Issuance Related to Stock-Based Compensation (2)	387,551	391,177	448,807
Balance, End of Year	29,910,439	34,746,904	34,480,181

(1) See Note 4 - Stock and Debt Repurchases for additional information.

(2) See Note 18 - Stock-Based Compensation for additional information.

Recent Accounting Pronouncements

In December 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-09 Income Taxes (Topic 740). The amendments in this update address investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The amendments in this update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation, (2) provide additional information for reconciling items that meet a quantitative threshold (if the effect of those reconciling items is equal to or greater than five percent of the amount computed by multiplying pretax income (or loss) by the applicable statutory income tax rate), (3) disclose the amount of income taxes paid (net of refunds received) disaggregated by federal (national), state, and foreign taxes, (4) disclose the amount of income taxes paid (net of refunds received) disaggregated by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than five percent of total income taxes paid (net of refunds received), (5) disclose income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign, and (6) disclose income tax expense (or benefit) from continuing operations disaggregated by federal (national), state, and foreign. The amendments in this update are effective for annual periods beginning after December 15, 2024, and should be applied prospectively. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

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In November 2023, the FASB issued ASU 2023-07 Segment Reporting (Topic 280). The amendments in this update improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. Topic 280 requires a public entity to report a measure of segment profit or loss that the chief operating decision maker uses to assess segment performance and make decisions about allocating resources. Topic 280 also requires other specified segment items and amounts, such as depreciation, amortization, and depletion expense, to be disclosed under certain circumstances. The amendments in this update do not change or remove those disclosure requirements. The amendments in this update also do not change how a public entity identifies its operating segments, aggregates those operating segments, or applies the quantitative thresholds to determine its reportable segments. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 and should be applied retrospectively. Management is currently evaluating the impact of this guidance, but does not expect this update to have a material impact on the Company's financial statements.

Reclassifications

Certain amounts in prior periods have been reclassified to conform with the report classifications of the current period. These reclassifications had no effect on previously reported total assets, stockholders' equity, net income or cash flows from operating activities.

NOTE 2—REVENUE FROM CONTRACTS WITH CUSTOMERS:

The following tables disaggregate CONSOL Energy's revenue from contracts with customers by product type and market:


	For the Year Ended December 31, 2023
	Domestic		Export		Total
Power Generation	$	672,509	$	346,671	$	1,019,180
Industrial	34,453		738,189		772,642
Metallurgical	10,671		303,873		314,544
Total Coal Revenue	717,633		1,388,733		2,106,366
Terminal Revenue					106,166
Freight Revenue					294,103
Total Revenue from Contracts with Customers					$	2,506,635

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	For the Year Ended December 31, 2022
	Domestic		Export		Total
Power Generation	$	908,666	$	393,647	$	1,302,313
Industrial	19,231		391,872		411,103
Metallurgical	16,637		288,609		305,246
Total Coal Revenue	944,534		1,074,128		2,018,662
Terminal Revenue					78,915
Freight Revenue					182,441
Total Revenue from Contracts with Customers					$	2,280,018


	For the Year Ended December 31, 2021
	Domestic		Export		Total
Power Generation	$	571,622	$	118,361	$	689,983
Industrial	12,377		296,003		308,380
Metallurgical	6,942		86,717		93,659
Total Coal Revenue	590,941		501,081		1,092,022
Terminal Revenue					65,193
Freight Revenue					103,819
Total Revenue from Contracts with Customers					$	1,261,034

Coal Revenue

The Company has disaggregated its coal revenue, derived from the PAMC and the Itmann Mining Complex, between domestic and export revenues, as well as industrial, power generation and metallurgical markets. Domestic coal revenue tends to be derived from contracts that typically have a term of one year or longer, and the pricing is typically fixed. Historically, export coal revenue tended to be derived from spot or shorter-term contracts with pricing determined closer to the time of shipment or based on a market index; however, the Company has secured several long-term export contracts with varying pricing arrangements. Coal revenue derived from the Itmann Mining Complex consists primarily of metallurgical coal sales, while coal revenue derived from the PAMC services the industrial, power generation and metallurgical markets due to the nature of its coal quality characteristics.

CONSOL Energy's coal revenue is recognized when the performance obligation has been satisfied, and the corresponding transaction price has been determined. Generally, title passes when coal is loaded at the coal preparation facilities, at terminal locations or other customer destinations. The Company's coal contract revenue per ton is fixed or determinable based upon either fixed forward pricing or pricing derived from established indices and adjusted for nominal quality characteristics. Some coal contracts also contain positive electric power price-related adjustments, which represent market-driven price adjustments, in addition to a fixed base price per ton. The Company’s coal contracts generally do not allow for retroactive adjustments to pricing after title to the coal has passed and typically do not have significant financing components.

The estimated transaction price from each of the Company's contracts is based on the total amount of consideration to which the Company expects to be entitled under the contract. Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services and per ton price fluctuations based on certain coal sales price indices. The estimated transaction price for each contract is allocated to the Company's performance obligations based on relative stand-alone selling prices determined at contract inception. The Company has determined that each ton of coal represents a separate and distinct performance obligation.

While CONSOL Energy does, from time to time, experience costs of obtaining coal customer contracts with amortization periods greater than one year, those costs are generally immaterial. At December 31, 2023 and 2022, the Company did not have any capitalized costs to obtain customer contracts on its Consolidated Balance Sheets. For the years ended December 31, 2023, 2022 and 2021, the Company has not recognized any amortization of previously existing capitalized costs of obtaining customer contracts. Further, the Company has not recognized any coal revenue in the current period that is not a result of current period performance.

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Terminal Revenue

Terminal revenues are attributable to the Company's CONSOL Marine Terminal and include revenues earned from providing receipt and unloading of coal from rail cars, transporting coal from the receipt point to temporary storage or stockpile facilities located at the Terminal, stockpiling, blending, weighing, sampling, redelivery, and loading of coal onto vessels. Revenues for these services are earned and performance obligations are considered fulfilled as the services are performed.

The CONSOL Marine Terminal does not normally experience material costs of obtaining customer contracts with amortization periods greater than one year. At December 31, 2023 and 2022, the Company did not have any capitalized costs to obtain customer contracts on its Consolidated Balance Sheets. For the years ended December 31, 2023, 2022 and 2021, the Company has not recognized any amortization of previously existing capitalized costs of obtaining Terminal customer contracts. Further, the Company has not recognized any revenue in the current period that is not a result of current period performance.

Freight Revenue

Some of CONSOL Energy's coal contracts require that the Company sell its coal at locations other than its coal preparation plants. The cost to transport the Company's coal to the ultimate sales point is passed through to the Company's customers and CONSOL Energy recognizes the freight revenue equal to the transportation costs when title to the coal passes to the customer.

Contract Balances

Contract assets, when present, are recorded separately from trade receivables in the Company's Consolidated Balance Sheets and are reclassified to trade receivables as title passes to the customer and the Company's right to consideration becomes unconditional. Credit is extended based on an evaluation of a customer's financial condition and a customer's ability to perform its obligations. CONSOL Energy typically does not have material contract assets that are stated separately from trade receivables since the Company's performance obligations are satisfied as control of the goods or services passes to the customer, thereby granting the Company an unconditional right to receive consideration. Contract liabilities relate to consideration received in advance of the satisfaction of the Company's performance obligations. Contract liabilities are recognized as revenue at the point in time when control of the goods passes to the customer, or over time when services are provided.

NOTE 3—MISCELLANEOUS OTHER INCOME:


	For the Years Ended December 31,
	2023		2022		2021
Contract Buyout	$	16,350	$	—	$	—
Interest Income	13,597		6,031		3,287
Royalty Income - Non-Operated Coal	8,855		10,258		8,661
Rental Income	2,129		2,239		1,095
Sale of Certain Mining Rights	—		—		21,756

Other	12,330		5,826		3,595
Miscellaneous Other Income	$	53,261	$	24,354	$	38,394

Royalty income represents earned revenue related to overriding royalty agreements or coal reserve leases between the Company and third-party operators.

The sale of certain mining rights involved transactions in connection with future coal reserves completed in the year ended December 31, 2021.

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NOTE 4— STOCK AND DEBT REPURCHASES:

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 (the “Second Lien Notes”). Since the program's inception, the Company's Board of Directors has subsequently amended the program several times. The most recent amendment occurred in April 2023, in which the aggregate limit of the Company's repurchase authority was raised to $1,000,000. The program terminates on December 31, 2024.

During the year ended December 31, 2023, the Company did not make any open market repurchases of its Second Lien Notes in accordance with this program. During the years ended December 31, 2022 and 2021, the Company spent $26,387 to repurchase $25,000 and spent $17,092 to repurchase $18,040 of its Second Lien Notes, respectively, in accordance with this program. During the years ended December 31, 2023 and 2022, the Company repurchased and retired 5,224,016 and 124,454 shares of the Company's common stock at an average price of $75.69 and $64.18 per share, respectively. No shares of common stock were repurchased under this program during the year ended December 31, 2021.

NOTE 5—INCOME TAXES:

The components of income tax expense were as follows:


	For the Years Ended December 31,
	2023		2022		2021
Current:
U.S. Federal	$	100,572	$	45,068	$	13,769
U.S. State	7,287		7,238		2,145
Non-U.S.	—		(235)		143
	107,859		52,071		16,057
Deferred:
U.S. Federal	12,528		37,154		(16,657)
U.S. State	1,593		12,233		1,897
	14,121		49,387		(14,760)

Total Income Tax Expense	$	121,980	$	101,458	$	1,297

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A reconciliation of income tax expense and the amount computed by applying the statutory federal income tax rate of 21% to income from operations before income tax is:


	For the Years Ended December 31,
	2023				2022				2021
	Amount		Percent		Amount		Percent		Amount		Percent
Statutory U.S. federal income tax rate	$	163,353	21.0	%	$	119,372	21.0	%	$	7,436	21.0	%
State income taxes, net of federal tax benefit	7,618		1.0		11,110		2.0		(642)		(1.8)
Effect of foreign income taxes	—		—		(241)		—		125		0.4
Excess tax depletion	(26,802)		(3.5)		(32,431)		(5.7)		(10,535)		(29.8)
Foreign derived intangible income	(23,545)		(3.0)		(4,906)		(0.9)		—		—
Uncertain tax positions	36		—		(792)		(0.1)		1,473		4.2
Compensation	2,284		0.3		4,178		0.7		3,192		9.0
Valuation allowance	—		—		(937)		(0.2)		(544)		(1.5)
Tax credits	(700)		(0.1)		(350)		(0.1)		(210)		(0.6)
State rate change and prior period adjustments	(809)		(0.1)		5,397		0.9		642		1.8
Other	545		0.1		1,058		0.2		360		1.0
Income Tax Expense / Effective Rate	$	121,980	15.7	%	$	101,458	17.8	%	$	1,297	3.7	%

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Significant components of deferred tax assets and liabilities were as follows:


	December 31,
	2023		2022
Deferred Tax Asset:
Postretirement benefits other than pensions	$	47,730	$	56,119
Asset retirement obligations	41,400		44,680
Pneumoconiosis benefits	33,867		33,946
Compensation	8,317		8,826
Workers' compensation	6,461		7,099
State bonus, net of Federal	1,917		2,973
Long-term disability	1,280		1,463
Operating lease liability	1,033		46
Net operating loss	238		211
Financing	124		838
Other	8,910		4,957
Total Deferred Tax Asset	151,277		161,158
Valuation Allowance	—		—
Net Deferred Tax Asset	151,277		161,158

Deferred Tax Liability:
Equity Partnerships	(122,220)		(118,231)
Property, plant and equipment	(52,409)		(54,322)
Advance mining royalties	(6,476)		(6,782)
Salary retirement	(5,468)		(3,737)
Right of use assets	(923)		—
Total Deferred Tax Liability	(187,496)		(183,072)

Net Deferred Tax Liability	$	(36,219)	$	(21,914)

At December 31, 2023, the Company has net operating loss carryforwards of approximately $238 for state income tax purposes, which will, if ultimately utilized, offset future taxable income. These net operating losses, if unused, will expire in 2041.

As required by U.S. GAAP, a valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Management must review all available evidence, both positive and negative, in determining the need for a valuation allowance. As of December 31, 2023 and 2022, no valuation allowance has been recorded.

Unrecognized Tax Benefits

The Company utilizes the “more likely than not” standard in recognizing a tax benefit in its financial statements. For the years ended December 31, 2023 and 2022, a reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

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	December 31,
	2023		2022

Balance at January 1	$	1,941	$	3,633
Additions based on tax positions related to the current year	22		384
Additions for tax positions of prior years	24		—
Reductions for tax positions of prior years	—		(1,168)
Reductions due to the statute of limitations	—		—
Settlements	—		(908)

Balance at December 31	$	1,987	$	1,941

The Company recorded an unrecognized tax benefit for the tax years ending December 31, 2023 and 2022 of $1,987 and $1,941, respectively, related to a position taken on state taxes. The actual amount of any change to the unrecognized tax benefit could vary depending on the timing and nature of the settlement; therefore, an estimate of change cannot be provided. Related interest and penalties were not accrued as these were estimated to be immaterial.

The Company is subject to taxation in the United States and its various states, as well as Canada and its various provinces. The Company is subject to examination for the tax periods 2018 through 2023 for federal and state returns.

NOTE 6—CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS:


	December 31,
	2023		2022
Cash and Cash Equivalents	$	199,371	$	273,070
Restricted Cash - Current(1)	43,897		40,366
Restricted Cash - Non-current(1)	—		13,516
Cash and Cash Equivalents and Restricted Cash	$	243,268	$	326,952

(1) Restricted Cash - Current is included in Other Current Assets in the accompanying Consolidated Balance Sheets. Restricted Cash - Non-current is included in Other Noncurrent Assets, net in the accompanying Consolidated Balance Sheets.

During the year ended December 31, 2023, the Company invested in marketable debt securities, primarily comprised of highly liquid U.S. Treasury securities. The investments are held in the custody of financial institutions. These securities are classified as available-for-sale securities and have maturity dates ranging from January 2024 through December 2024, and are classified as current assets accordingly.

The Company's investments in available-for-sale securities are as follows:


	December 31, 2023
					Gross Unrealized
	Amortized Cost		Allowance for Credit Losses		Gains		Losses		Fair Value
U.S. Treasury Securities	$	81,829	$	—	$	103	$	—	$	81,932

Available-for-sale investments are reported at fair value and any unrealized gains or losses are recognized in other comprehensive income, net of tax. The unrealized gains in the Company's portfolio at December 31, 2023 are the result of normal market fluctuations. Interest and dividends are included in net income when earned.

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NOTE 7—CREDIT LOSSES:

Trade receivables are recorded at the invoiced amount and do not bear interest. Credit is extended based on an evaluation of a customer's financial condition, the importance of the customer or market for future business, and a customer's ability to perform its obligations. Trade receivable balances are monitored against approved credit terms. Credit terms are reviewed and adjusted as considered necessary based on changes to a customer's credit profile. If a customer's credit deteriorates, the Company may reduce credit risk exposure by reducing credit terms, obtaining letters of credit, obtaining credit insurance, or requiring pre-payment for shipments. Other non-trade contractual arrangements consist primarily of overriding royalty agreements and other financial arrangements between the Company and various counterparties.

The Company may be at risk of exposure to credit losses primarily through sales of products and services. The Company's expected loss allowance methodology for accounts receivable is developed using historical collection experience, current and future economic and market conditions, and a review of the current status of customers' trade and other accounts receivables. Due to the short-term nature of such receivables, the estimate of the amount of accounts receivable that may not be collected is based on an aging of the accounts receivable balances and the financial condition of customers. Additionally, specific allowance amounts may be necessary from time to time and are established to record the appropriate provision for customers that have a higher probability of default. The Company's monitoring activities include timely account reconciliations, dispute resolution, payment confirmation, and consideration of customers' financial condition and macroeconomic conditions. Balances are written off when determined to be uncollectible.

Management estimates the allowance balance using relevant available information, from internal and external sources, relating to past events, current conditions, and reasonable and supportable forecasts. Historical credit loss experience provides the basis for the estimation of expected credit losses. Adjustments to historical loss information are made for changes to the assessment of anticipated payment, changes in economic conditions, current industry trends in the markets the Company serves, and changes in the financial health of the Company's counterparties.

The following table provides a roll-forward of the allowance for credit losses that is deducted from the amortized cost basis of accounts receivable and other non-trade contractual arrangements to present the net amount expected to be collected.


	Trade Receivables		Other Non-Trade Contractual Arrangements

Beginning Balance, December 31, 2022	$	1,731	$	7,051
Provision for expected credit losses	(1,265)		498
Write-off of uncollectible accounts	—		(45)
Ending Balance, December 31, 2023	$	466	$	7,504

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NOTE 8—ASSET RETIREMENT OBLIGATIONS:

CONSOL Energy accrues for mine closing costs, perpetual water treatment costs, and costs associated with the plugging of degasification wells using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement obligations by increasing the carrying amount of related long-lived assets.

The reconciliation of changes in the Company's asset retirement obligations at December 31, 2023 and 2022 is as follows:


	As of December 31,
	2023		2022
Balance at Beginning of Period	$	251,502	$	238,118
Accretion Expense	19,843		18,747
Payments	(22,771)		(18,025)
Revisions in Estimated Cash Flows	4,533		12,801
Other	(11,915)		(139)
Balance at End of Period	$	241,192	$	251,502

For the year ended December 31, 2023, Other consists of $(11,915) attributed to conveyances of several gas wells to third parties.

NOTE 9—INVENTORIES:

Inventory components consist of the following:


	December 31,
	2023		2022
Coal	$	17,128	$	11,315
Supplies	71,026		54,975
Total Inventories	$	88,154	$	66,290

NOTE 10—PROPERTY, PLANT AND EQUIPMENT:

Property, plant and equipment consists of the following:


	December 31,
	2023		2022
Plant and Equipment	$	3,458,655	$	3,330,755
Coal Properties and Surface Lands	906,343		898,628
Airshafts	492,806		481,090
Mine Development	366,260		366,241
Advance Mining Royalties	328,340		331,863
Total Property, Plant and Equipment	5,552,404		5,408,577
Less: Accumulated Depreciation, Depletion and Amortization	3,649,281		3,448,495
Total Property, Plant and Equipment - Net	$	1,903,123	$	1,960,082

As of December 31, 2023 and 2022, property, plant and equipment includes gross assets under finance leases of $44,622 and $90,516, respectively. Accumulated amortization for finance leases was $31,873 and $54,028 at December 31, 2023 and 2022, respectively. Amortization expense for assets under finance leases approximated $25,400, $24,206 and $27,846 for the years ended December 31, 2023, 2022 and 2021, respectively, and is included in Depreciation, Depletion

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and Amortization in the accompanying Consolidated Statements of Income. See Note 14 - Leases for further discussion of finance leases.

NOTE 11—ACCOUNTS RECEIVABLE SECURITIZATION:

Loans under the securitization facility accrue interest at a reserve-adjusted market index rate equal to the applicable term Secured Overnight Financing Rate (“SOFR”). Loans and letters of credit under the securitization facility also accrue a program fee and a letter of credit participation fee, respectively, ranging from 2.00% to 2.50% per annum depending on the total net leverage ratio of CONSOL Energy. In addition, the SPV paid certain structuring fees to PNC Capital Markets LLC and pays other customary fees to the lenders, including a fee on unused commitments equal to 0.60% per annum.

At December 31, 2023, the Company's eligible accounts receivable yielded $72,125 of borrowing capacity. At December 31, 2023, the facility had no outstanding borrowings and $72,087 of letters of credit outstanding, leaving available borrowing capacity of $38. At December 31, 2022, the Company's eligible accounts receivable yielded $85,179 of borrowing capacity. At December 31, 2022, the facility had no outstanding borrowings and $83,465 of letters of credit outstanding, leaving available borrowing capacity of $1,714. Costs associated with the receivables facility totaled $1,423, $1,101 and $1,048 for the years ended December 31, 2023, 2022 and 2021, respectively. The Company has not derecognized any receivables due to its continued involvement in the collections efforts.

NOTE 12—OTHER ACCRUED LIABILITIES:


	December 31,
	2023		2022
Subsidence Liability	$	105,322	$	96,623
Accrued Compensation and Benefits	73,763		67,893
Accrued Other Taxes	12,276		10,551
Deferred Revenue	9,517		966
Accrued Interest	6,283		7,942
Other	10,457		10,427
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations	28,571		29,644
Postretirement Benefits Other than Pensions	19,327		22,436
Pneumoconiosis Benefits	15,071		12,723
Workers' Compensation	10,019		10,451
Total Other Accrued Liabilities	$	290,606	$	269,656

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NOTE 13—LONG-TERM DEBT:


	December 31,
	2023		2022
Debt:
MEDCO Revenue Bonds in Series due September 2025 at 5.75%	$	102,865	$	102,865
9.00% PEDFA Solid Waste Disposal Revenue Bonds due April 2028	75,000		75,000
Advance Royalty Commitments (8.80% and 8.09% Weighted Average Interest Rate, respectively)	5,922		7,716
Other Debt Arrangements	1,419		2,400
11.00% Senior Secured Second Lien Notes due November 2025	—		99,107
Term Loan B due in September 2024 (Principal of $63,590 less Unamortized Discount of $106, 8.92% Weighted Average Interest Rate at December 31, 2022)	—		63,484
Less: Unamortized Debt Issuance Costs	(1,686)		(3,721)
	183,520		346,851
Less: Amounts Due in One Year*	(1,635)		(4,741)
Long-Term Debt	$	181,885	$	342,110

*Excludes current portion of Finance Lease Obligations of $9,471 and $24,105 at December 31, 2023 and 2022, respectively.

Annual undiscounted maturities on the Company's debt instruments during the next five years and thereafter are as follows:


Year ended December 31,	Amount
2024	$	1,635
2025	103,900
2026	883
2027	816
2028	75,697
Thereafter	2,275
Total Long-Term Debt Maturities	$	185,206

Revolving Credit Facility

In November 2017, CONSOL Energy entered into a revolving credit facility with PNC Bank, N.A. (the “Revolving Credit Facility”). The Revolving Credit Facility has been amended several times, the most recent of which occurred in June 2023. This amendment increased the available revolving commitments from $260,000 to $355,000 and provides for the Company's ability to increase the revolving commitments or issue term loans in an additional amount not to exceed $45,000 and up to an aggregate total amount of $400,000. The maturity date of the Revolving Credit Facility is July 18, 2026.

Borrowings under the Company's Revolving Credit Facility bear interest at a floating rate that is, at the Company's option, either (i) SOFR plus the applicable SOFR adjustment (as defined therein) depending on the applicable interest period plus an applicable margin or (ii) an alternate base rate plus an applicable margin. The applicable margin for the Revolving Credit Facility depends on the total net leverage ratio. Obligations under the Revolving Credit Facility are guaranteed by (i) all owners of the PAMC held by the Company, (ii) any other members of the Company’s group that own any portion of the collateral securing the Revolving Credit Facility, and (iii) subject to certain customary exceptions and agreed materiality thresholds, all other existing or future direct or indirect wholly-owned restricted subsidiaries of the Company. The obligations are secured by, subject to certain exceptions (including a limitation of pledges of equity interests in certain subsidiaries and certain thresholds with respect to real property), a first-priority lien on (i) the Company’s interest in the PAMC, (ii) the equity interests in PA Mining Complex LP held by the Company, (iii) the CONSOL Marine Terminal, (iv) the Itmann Mining Complex and (v) the 1.3 billion tons of Greenfield Reserves and Resources.

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The Revolving Credit Facility contains a number of customary affirmative covenants and a number of negative covenants, including (subject to certain exceptions) limitations on (among other things): indebtedness, liens, investments, acquisitions, dispositions, restricted payments and prepayments of junior indebtedness. The Revolving Credit Facility also includes covenants relating to (i) a maximum first lien gross leverage ratio, (ii) a maximum total net leverage ratio, and (iii) a minimum fixed charge coverage ratio. The maximum first lien gross leverage ratio is calculated as the ratio of Consolidated First Lien Debt to Consolidated EBITDA. Consolidated EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, extraordinary gains and losses, gains and losses on discontinued operations and gains and losses on debt extinguishment. The maximum total net leverage ratio is calculated as the ratio of Consolidated Indebtedness, minus Cash on Hand, to Consolidated EBITDA. The minimum fixed charge coverage ratio is calculated as the ratio of Consolidated EBITDA to Consolidated Fixed Charges. Consolidated Fixed Charges, as used in the covenant calculation, include cash interest payments, cash payments for income taxes, scheduled debt repayments, Maintenance Capital Expenditures and cash payments related to legacy employee liabilities to the extent in excess of amounts accrued in the calculation of Consolidated EBITDA. Under the Revolving Credit Facility, the maximum first lien gross leverage ratio shall be 1.50 to 1.00, the maximum total net leverage ratio shall be 2.50 to 1.00 and the minimum fixed charge coverage ratio shall be 1.10 to 1.00.

The Company's first lien gross leverage ratio was 0.01 to 1.00 at December 31, 2023. The Company's total net leverage ratio was (0.08) to 1.00 at December 31, 2023. The Company's fixed charge coverage ratio was 3.42 to 1.00 at December 31, 2023. The Company was in compliance with all of its financial covenants under the Revolving Credit Facility as of December 31, 2023.

At December 31, 2023, the Revolving Credit Facility had no borrowings outstanding and $111,186 of letters of credit outstanding, leaving $243,814 of unused capacity. At December 31, 2022, the Revolving Credit Facility had no borrowings outstanding and $103,029 of letters of credit outstanding, leaving $296,971 of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CONSOL Energy sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

The SPV is a non-guarantor subsidiary of the Revolving Credit Facility, and the SPV holds the assets pledged to the lender in the securitization facility. The SPV had total assets of $147,918 and $158,877, comprised mainly of $147,612 and $158,127 trade receivables, net, at December 31, 2023 and 2022, respectively. For the years ended December 31, 2023, 2022 and 2021, net income (loss) attributable to the SPV was $5,129, $12,330 and $(54), respectively, which primarily reflected intercompany fees related to purchasing the receivables, which are eliminated in the Consolidated Financial Statements contained within this Annual Report on Form 10-K. During the years ended December 31, 2023, 2022 and 2021, there were no borrowings or payments under the accounts receivable securitization facility. See Note 11 - Accounts Receivable Securitization for additional information.

Second Lien Notes

In November 2017, CONSOL Energy issued $300,000 in aggregate principal amount of Second Lien Notes pursuant to an indenture (the “Indenture”) dated as of November 13, 2017, by and between the Company and UMB Bank, N.A., a national banking association, as trustee and collateral trustee (the “Trustee”). On November 28, 2017, certain subsidiaries of the Company executed a supplement to the Indenture and became party to the Indenture as a guarantor (the “Guarantors”). The Second Lien Notes were secured by second priority liens on substantially all of the assets of the Company and the Guarantors that are pledged on a first-priority basis as collateral securing the Company’s obligations under the Revolving Credit Facility (described above), subject to certain exceptions under the Indenture.

The Indenture contained covenants that limited the ability of the Company and the Guarantors to (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) create liens to secure indebtedness; (iii) declare or pay dividends on the Company’s common stock, redeem stock or make other distributions to the Company’s stockholders; (iv) make investments; (v) pay or make dividends, loans or other asset transfers from the Company’s restricted subsidiaries; (vi) merge or consolidate, or sell, transfer, lease or dispose of substantially all of the Company’s assets; (vii) sell or otherwise dispose of certain assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants were subject to important exceptions and qualifications. If the Second Lien Notes achieved an investment grade rating from both Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc. and no default under the Indenture existed, many of the foregoing covenants would have terminated and ceased to apply.

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During the year ended December 31, 2023, the Company spent $101,832 to fully redeem the remaining balance of $99,107 of its outstanding Second Lien Notes. During the year ended December 31, 2022, the Company spent $26,387 to repurchase $25,000, and spent $25,687 to redeem $25,000 of its outstanding Second Lien Notes. As a result of these transactions, losses of $2,725 and $5,623 were incurred and are included in Loss (Gain) on Debt Extinguishment on the Consolidated Statements of Income for the years ended December 31, 2023 and 2022, respectively.

PEDFA Bonds

In April 2021, CONSOL Energy borrowed the proceeds received from the sale of tax-exempt bonds issued by PEDFA in an aggregate principal amount of $75,000 (the “PEDFA Bonds”). The PEDFA Bonds bear interest at a fixed rate of 9.00% for an initial term of seven years. The PEDFA Bonds mature on April 1, 2051 but are subject to mandatory purchase by the Company on April 13, 2028, at the expiration of the initial term rate period. The PEDFA Bonds were issued pursuant to an indenture (the “PEDFA Indenture”) dated as of April 1, 2021, by and between PEDFA and Wilmington Trust, N.A., a national banking association, as trustee (the “PEDFA Notes Trustee”). PEDFA made a loan of the proceeds of the PEDFA Bonds to the Company pursuant to a Loan Agreement (the “Loan Agreement”) dated as of April 1, 2021 between PEDFA and the Company. Under the terms of the Loan Agreement, the Company agreed to make all payments of principal, interest and other amounts at any time due on the PEDFA Bonds or under the PEDFA Indenture. PEDFA assigned its rights as lender under the Loan Agreement, excluding certain reserved rights, to the PEDFA Notes Trustee. Certain subsidiaries of the Company (the “PEDFA Notes Guarantors”) executed a Guaranty Agreement (the “Guaranty”) dated as of April 1, 2021 in favor of the PEDFA Notes Trustee, guarantying the obligations of the Company under the Loan Agreement to pay the PEDFA Bonds when and as due. The obligations of the Company under the Loan Agreement and of the PEDFA Notes Guarantors under the Guaranty are secured by second priority liens on substantially all of the assets of the Company and the PEDFA Notes Guarantors. The Loan Agreement and Guaranty incorporate by reference covenants in the Indenture under which the Second Lien Notes were issued (discussed previously).

The Company started a capital construction project on the PAMC coarse refuse disposal area in 2017, which is now funded, in part, by the proceeds from the PEDFA Bonds. The Company expects to expend these funds as qualified work is completed. During the years ended December 31, 2023 and 2022, the Company utilized restricted cash in the amount of $24,705 and $11,196, respectively, for qualified expenses. Additionally, the Company had $12,177 and $35,516 in restricted cash at December 31, 2023 and 2022, respectively, associated with this financing that will be used to fund future spending on the coarse refuse disposal area.

NOTE 14—LEASES:

The Company has operating leases for mining and other equipment used in operations and office space. Many leases include one or more options to renew, some of which include options to extend, the leases, and some leases include options to terminate or buy out the leases within a set period of time. In certain of the Company’s lease agreements, the rental payments are adjusted periodically to reflect actual charges incurred for inflation and/or changes in other indexes. Many of the Company's operating lease payments for mining equipment contain a variable component which is calculated based upon production metrics such as feet of advance or raw tonnage mined. While most of the Company's leases contain clauses regarding the general condition of the equipment upon lease termination, they do not contain residual value guarantees.

The Company determines if an arrangement is an operating or finance lease at inception of the applicable lease. For leases where the Company is the lessee, Right of Use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent an obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available on the commencement date in determining the present value of lease payments. The ROU asset also consists of any prepaid lease payments, lease incentives received, and costs which will be incurred in exiting a lease. The lease terms used to calculate the ROU asset and related lease liability include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Lease expense for operating leases is recognized on a straight-line basis over the lease term as an operating expense while the expense for finance leases is recognized as depreciation expense and interest expense using the interest method of recognition. Further, the Company made an accounting policy election not to apply the recognition and measurement requirements to short-term leases, defined as leases with an initial term of twelve months or less. CONSOL Energy will recognize those lease payments in the Consolidated Statements of Income over the lease term. For the years ended December 31, 2023 and 2022, these short-term lease expenses were not material to the Company's financial statements.

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For the years ended December 31, 2023 and 2022, the components of operating lease expense were as follows:


	December 31,
	2023		2022
Fixed operating lease expense	$	6,447	$	11,467
Variable operating lease expense	8,358		10,752
Total operating lease expense	$	14,805	$	22,219

Supplemental cash flow information related to the Company's operating leases for the years ended December 31, 2023 and 2022 was as follows:


	December 31,
	2023		2022
Cash paid for amounts included in the measurement of operating lease liabilities	$	6,148	$	22,020

The following table presents the lease balances within the Consolidated Balance Sheets, weighted average lease term, and the weighted average discount rate related to the Company's operating leases at December 31, 2023 and 2022:


		December 31,
Lease Assets and Liabilities	Classification	2023			2022
Assets:
Operating Lease ROU Assets	Other Assets	$	14,658		$	19,799

Liabilities:
Current:
Operating Lease Liabilities	Operating Lease Liabilities	$	4,769		$	4,922
Long-Term:
Operating Lease Liabilities	Operating Lease Liabilities	$	10,385		$	15,073
Total Operating Lease Liabilities		$	15,154		$	19,995

Weighted average remaining lease term (in years)		4.46			4.83
Weighted average discount rate		7.21		%	7.13		%

The Company also enters into finance leases for mining equipment and automobiles. Assets arising from finance leases are included in property, plant and equipment-net and the liabilities are included in current portion of long-term debt and long-term debt in the accompanying Consolidated Balance Sheets.

For the years ended December 31, 2023 and 2022, the components of finance lease expense were as follows:


	December 31,
	2023		2022
Amortization of right of use assets	$	25,400	$	24,206
Interest expense	1,712		2,751
Total finance lease expense	$	27,112	$	26,957

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The following table presents the weighted average lease term and weighted average discount rate related to the Company's finance leases as of December 31, 2023 and 2022:


	December 31, 2023		December 31, 2022
Weighted average remaining lease term (in years)	1.64		1.62
Weighted average discount rate	6.68	%	6.53	%

The following table presents the future maturities of the Company's operating and finance lease liabilities, together with the present value of the net minimum lease payments, at December 31, 2023:


	Finance Leases		Operating Leases
2024	$	10,045	$	5,669
2025	3,649		4,135
2026	487		4,011
2027	369		658
2028	149		638
Thereafter	—		2,799
Total minimum lease payments	14,699		17,910
Less amount representing interest	1,046		2,756
Present value of minimum lease payments	$	13,653	$	15,154

NOTE 15—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

Pension

CONSOL Energy has non-contributory defined benefit retirement plans. The benefits for these plans are based primarily on years of service and employees' pay. CONSOL Energy's qualified pension plan (the “Pension Plan”) allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees' election.

According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the year ended December 31, 2021. Accordingly, CONSOL Energy recognized expense of $22 for the year ended December 31, 2021 in Operating and Other Costs in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement charges noted above also resulted in a remeasurement of the pension plan at June 30, 2021, which reduced the pension liability by $1,009. The settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $766 to Other Comprehensive Income, net of $265 in deferred taxes. Lump sum payments did not exceed this threshold during the years ended December 31, 2023 and 2022.

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CONSOL Energy (CEIX) 10-K2023 FY Annual report

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