Coronado Global Resources Inc. - Annual Report: 2021 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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(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, 2021

OR

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

For the transition period from                     to                     

Commission File Number: 000-56044

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Coronado Global Resources Inc.

(Exact name of registrant as specified in its charter)

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Level 33, Central Plaza One, 345 Queen Street

Brisbane, Queensland, Australia, 4000

(Address of principal executive offices) (Zip Code)

(61) 7 3031 7777

(Registrant’s telephone number, including area code)

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

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

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, 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.

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No  ☒

The registrant’s common stock is publicly traded on the Australian Securities Exchange in the form of CHESS Depositary Interests, or CDIs, convertible at the option of the holders into shares of the registrant’s common stock on a 10-for-1 basis. The aggregate market value of the registrant’s common stock, par value $0.01 per share, in the form of CDIs, held by non-affiliates of the registrant (without admitting that any person whose shares are not included in such calculation is an affiliate), computed by reference to the price at which the CDIs were last sold on June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, as reported on the Australian Securities Exchange, was $523,449,082.

The total number of shares of the registrant’s common stock, par value $0.01 per share, outstanding on December 31, 2021, including shares of common stock underlying CDIs, was 167,645,373.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement to be filed with the Securities and Exchange Commission in connection with the registrants 2022 annual meeting of stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K. Documents incorporated by reference in this report are listed in the Exhibit Index of this Annual Report on Form 10-K.

TABLE OF CONTENTS

Table of Contents

EXPLANATORY NOTE

Unless otherwise noted, references in this Annual Report on Form 10-K to “we,” “us,” “our,” “Company,” or “Coronado” refer to Coronado Global Resources Inc. and its consolidated subsidiaries and associates, unless the context indicates otherwise.

All production and sales volumes contained in this Annual Report on Form 10-K are expressed in metric tons, or Mt, millions of metric tons, or MMt, or millions of metric tons per annum, or MMtpa, except where otherwise stated. One Mt (1,000 kilograms) is equal to 2,204.62 pounds and is equivalent to 1.10231 short tons. In addition, all dollar amounts contained herein are expressed in United States dollars, or US$, except where otherwise stated. References to “A$” are references to Australian dollars, the lawful currency of the Commonwealth of Australia, or the Commonwealth. Some numerical figures included in this Annual Report on Form 10-K have been subject to rounding adjustments. Accordingly, numerical figures shown as totals in certain tables may not equal the sum of the figures that precede them.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, concerning our business, operations, financial performance and condition, the coal, steel and other industries, as well as our plans, objectives and expectations for our business, operations, financial performance and condition. Forward-looking statements may be identified by words such as “may,” “could,” “believes,” “estimates,” “expects,” “intends,” “plans,” “anticipate,” “forecast,” “outlook,” “target,” “likely,” “considers” and other similar words.

Any forward-looking statements involve known and unknown risks, uncertainties, assumptions and other important factors that could cause actual results, performance, events or outcomes to differ materially from the results, performance, events or outcomes expressed or anticipated in these statements, many of which are beyond our control. Such forward-looking statements are based on an assessment of present economic and operating conditions on a number of best estimate assumptions regarding future events and actions. These factors are difficult to accurately predict and may be beyond our control. Factors that could affect our results, our announced plans or an investment in our securities include, but are not limited to:

•uncertainty in global economic conditions, including the extent, duration and impact of the COVID-19 pandemic, as well as risks related to government actions with respect to trade agreements, treaties or policies;

•severe financial hardship, bankruptcy, temporary or permanent shut downs or operational challenges, due to the ongoing COVID-19 pandemic or any similar future health crisis, pandemic or epidemic, of one or more of our major customers, including customers in the steel industry, key suppliers/contractors, which among other adverse effects, could lead to reduced demand for our coal, increased difficulty collecting receivables and customers and/or suppliers asserting force majeure or other reasons for not performing their contractual obligations to us;

•our ability to generate sufficient cash to service our indebtedness and other obligations;

•our indebtedness and ability to comply with the covenants and other undertakings under the agreements governing such indebtedness;

•our ability to collect payments from our customers depending on their creditworthiness, contractual performance or otherwise;

•the prices we receive for our coal;

•the demand for steel products, which impacts the demand for our metallurgical, or Met, coals;

•risks inherent to mining;

•the loss of, or significant reduction in, purchases by our largest customers;

•risks unique to international mining and trading operations, including tariffs and other barriers to trade;

•unfavorable economic and financial market conditions;

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•our ability to continue acquiring and developing coal reserves that are economically recoverable;

•uncertainties in estimating our economically recoverable coal reserves;

•transportation for our coal becoming unavailable or uneconomic for our customers;

•the risk that we may be required to pay for unused capacity pursuant to the terms of our take-or-pay arrangements with rail and port operators;

•our ability to retain key personnel and attract qualified personnel;

•any failure to maintain satisfactory labor relations;

•our ability to obtain, renew or maintain permits and consents necessary for our operations;

•potential costs or liability under applicable environmental laws and regulations, including with respect to any exposure to hazardous substances caused by our operations, as well as any environmental contamination our properties may have or our operations may cause;

•extensive regulation of our mining operations and future regulations and developments;

•our ability to provide appropriate financial assurances for our obligations under applicable laws and regulations;

•assumptions underlying our asset retirement obligations for reclamation and mine closures;

•concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, which could result in increased regulation of coal combustion in many jurisdictions and divestment efforts affecting the investment community;

•the extensive forms of taxation that our mining operations are subject to, and future tax regulations and developments;

•any cyber-attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our customers or other third parties;

•a decrease in the availability or increase in costs of key supplies, capital equipment or commodities, such as diesel fuel, steel, explosives and tires;

•the risk that we may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets;

•risks related to divestitures and acquisitions;

•the risk that diversity in interpretation and application of accounting principles in the mining industry may impact our reported financial results; and

•other risks and uncertainties described in Item 1A. “Risk Factors.”

We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.

See Item 1A. “Risk Factors” and elsewhere in this Annual Report on Form 10-K for a more complete discussion of the risks and uncertainties mentioned above and for discussion of other risks and uncertainties we face that could cause actual results to differ materially from those expressed or implied by these forward-looking statements.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements, as well as others made in this Annual Report on Form 10-K and hereafter in our other filings with the Securities and Exchange Commission, or SEC, and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties.

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We caution you that the risks and uncertainties identified by us may not be all of the factors that are important to you. You should not interpret the disclosure of any risk to imply that the risk has not already materialized. Furthermore, the forward-looking statements included in this Annual Report on Form 10-K are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events, or otherwise, except as required by applicable law.

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PART I

ITEM 1. BUSINESS.

Overview

We are a leading producer, global marketer and exporter of a full range of Met coals. We own a portfolio of operating mines and development projects in Queensland in Australia, and in Virginia, West Virginia and Pennsylvania in the United States. We are one of the largest Met coal producers globally by export volume, serving customers on five continents.

Our operations in Australia, or our Australian Operations, consist of the 100%-owned Curragh producing mining property located in the Bowen Basin of Australia. Our operations in the United States, or our U.S. Operations, consists of two producing mining properties (Buchanan and Logan), one temporarily idled mining property (Greenbrier) and two development mining properties (Mon Valley, formerly named Pangburn-Shaner-Fallowfield, and Russell County), primarily located in the Central Appalachian region of the United States, or CAPP, all of which are 100%-owned. Our U.S. Operations and Australian Operations are strategically located for access to transportation infrastructure. In addition to Met coal, our Australian Operations sell thermal coal under a long-term legacy contract assumed in the acquisition of Curragh, which is used to generate electricity, to Stanwell Corporation Limited, or Stanwell, a Queensland government-owned entity and the operator of the Stanwell Power Station located near Rockhampton, Queensland, and some thermal coal in the export market. Our U.S. Operations also produce and sell some thermal coal that is extracted in the process of mining Met coal.

Our core business strategy focuses on the production of Met coal for the North American and seaborne export markets. Sales of Met coal represented 94.6% of our total coal revenues for the year ended December 31, 2021. Most of the Met coal that we produce is sold, directly or indirectly, to steel producers. Met coal sales represented 81.4% of our total volume of coal sold in 2021. The remaining 18.6% of our total volume sold in 2021 was thermal coal, the majority of which was sold to Stanwell.

Met coal is a key ingredient in the production of steel using blast furnaces, and approximately 770 kilograms of Met coal is required to produce one ton of steel.

We have a geographically diverse customer base, across a range of global markets. Major consumers of our seaborne Met coal in 2021 were located in high-growth Asian markets, Brazil and Europe. These consumers are all major global steel or Met coke producers. We are well-positioned in the key high-growth Asian markets (Japan, South Korea and India) as sales to direct end users in Asia represented 48.3% of our total revenue, including Tata Steel Limited, or Tata Steel, which accounted for 16.7% of total revenue, in 2021.

The charts below show the split of our direct sales by geographic region in 2021 and the split of our revenues and sales volume by export and domestic sales in 2019, 2020 and 2021.

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To support our operations, we have proven and probable coal reserves totaling 556 MMt as of December 31, 2021, 215 MMt and 341 MMt of which are in Australia and the United States, respectively. For more information regarding our coal reserves, see Item 2. “Properties.”

COVID-19

The ongoing COVID-19 global pandemic has continued to result in a challenging working environment. Authorities in many countries around the world have implemented numerous and varying measures to reduce the spread and limit the impact of COVID-19, including travel bans and restrictions, quarantines, curfews, stay-at-home orders, business shutdowns and closures. Many countries have implemented multi-stage policies with the goal of re-opening markets and boosting economic activity.

There is uncertainty regarding how the COVID-19 pandemic will continue to impact our business including whether it will result in further changes in demand for Met coal, increases in operating costs or impacts to our supply chain, and whether measures will result in port closures or border restrictions, each or all of which can impact our ability to produce and sell our products.

The safety and wellbeing of our workforce remains our highest priority and we continue to manage the potential threat of COVID-19 at our mines and offices. The Company’s COVID-19 Steering Committee, formed in 2020, has successfully monitored the effect of the pandemic across our Australian Operations and U.S. Operations and continues to implement proactive preventative measures to ensure the safety and well-being of employees and contractors. These procedures include increased screenings of employees as they arrive at the workplace, strict adherence to hygiene and social distancing guidelines while at work and also a cleaning and sanitization program for equipment and facilities.

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Throughout 2021 the COVID-19 Steering Committee focused on encouraging all workers across all jurisdictions to be vaccinated. This included providing access to educational materials about vaccine safety and efficiency, as well as arranging for several vaccination clinics to be held close to our U.S. Operations and Australian Operations in order to ensure access and availability for all employees. During the year ended December 31, 2021, we implemented a Vaccine Incentive Program at our U.S. Operations that provides cash payment to employees who provided proof of vaccination. Since the program commenced, vaccination rates amongst our U.S. workforce has improved significantly. At our Australian Operations, vaccination rates continue to increase as the Australian Federal and Queensland state government’s vaccination program roll out. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview”.

History and Australian Public Offering

We were founded in 2011 by Garold Spindler, James Campbell and a fund affiliated with The Energy & Minerals Group, or EMG, with the intention of evaluating, acquiring and developing Met coal properties.

Since 2011, Coronado Coal LLC, a Delaware limited liability company, and other affiliated entities, including Coronado Group LLC, a Delaware limited liability company, which we refer to, collectively, as Coronado Group, have grown the scale and platform of our current operations principally from four acquisitions:

•in 2013, Coronado Group acquired Greenbrier from Lehman Brothers;

•in 2014, Coronado Group acquired Logan from Cliffs Natural Resources Inc. (now known as Cleveland-Cliffs Inc.);

•in 2016, Coronado Group acquired Buchanan from CONSOL Energy Inc., or CONSOL Energy; and

•in 2018, Coronado Group acquired Wesfarmers Curragh Pty Ltd (now known as Coronado Curragh Pty Ltd), including the Curragh producing mining property, from Wesfarmers Ltd, or Wesfarmers.

Prior to the initial public offering, Coronado Global Resources Inc., our parent company, was a wholly-owned subsidiary of Coronado Group LLC, which is currently owned by funds managed by EMG, which we refer to, collectively, as the EMG Group, and certain members of our management.

On October 23, 2018, we completed an initial public offering on the Australian Securities Exchange, or ASX, which we refer to as the Australian IPO.

On May 14, 2021, we successfully completed the institutional component of a fully underwritten 1-for-4.73 pro-rata accelerated non-renounceable entitlement offer, or the Entitlement Offer. On completion, a total of 253,108,820 fully paid new CDIs (representing a beneficial interest in 25,310,882 shares of common stock) were issued, which are traded on the ASX.

On June 1, 2021, we successfully completed the retail component of the Entitlement Offer. On completion, a total of 39,466,010 fully paid new CDIs (representing a beneficial interest in 3,946,601 shares of common stock) were issued, which are traded on the ASX.

Coronado Group LLC, the Company’s controlling stockholder, exercised its right to participate in the institutional component of the Entitlement Offer and purchased 71,980,363 of the new CDIs (representing a beneficial interest in 7,198,036.3 shares of common stock).

As of December 31, 2021, the EMG Group and management beneficially own approximately 50.4% of the issued and outstanding shares of our common stock through their ownership of Coronado Group LLC. The remaining 49.6% is owned by public investors in the form of CDIs traded on the ASX. In addition, Coronado Group LLC holds one share of preferred stock Series A, par value $0.01 per share, of the Company, or the Series A Share, which is the only share of preferred stock issued and outstanding. The holder of the Series A Share is permitted to nominate and elect members of our Board of Directors in relation to the level of the holder’s aggregate beneficial ownership of shares of our common stock.

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Organizational Structure

The following chart shows our current organizational structure:

Overview of Operations

Met Coal

Met coals are primarily used in the manufacture of coke, which is used in the steel-making process, as well as direct injection into a blast furnace as a replacement for coke.

Sales of Met coal represented approximately 94.6% of our total coal revenues for the year ended December 31, 2021. Most of the Met coal that we produce is sold, directly or indirectly, to steel producers. The steel industry’s demand for Met coal is affected by several factors, including the cyclical nature of that industry’s business, general economic conditions and demand for steel, tariffs on steel and steel products, technological developments in the steelmaking process and the availability and cost of substitutes for steel, such as aluminum, composites and plastics. We compete based on coal quality and characteristics, price, customer service and support and reliability of supply. Seaborne Met coal import demand can be significantly impacted by the availability of indigenous coal production, particularly in the leading Met coal import countries of China and India, among others, and the competitiveness of seaborne Met coal supply, including from the leading Met coal exporting countries of Australia, the United States, Russia, Canada and Mongolia, among others.

Thermal Coal

Sales of thermal coal represented approximately 5.4% of our total coal revenues for the year ended December 31, 2021. The thermal coal we produce is predominantly a byproduct of mining Met coal. The thermal coal we produce is sold, directly or indirectly, to power stations, predominantly Stanwell, as an energy source in the generation of electricity. Demand for our thermal coal products is impacted by economic conditions, environmental regulation, demand for electricity, including the impact of energy efficient products, and the cost of electricity generation from alternative fuels. Our thermal coal products primarily compete with producers of other forms of electric generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use.

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Segments

In accordance with Accounting Standards Codification, or ASC, Topic 280, Segment Reporting, we have adopted the following reporting segments:

•Australia; and

•United States.

In addition, “Other and Corporate” is not a reporting segment but is disclosed for the purposes of reconciliation to our consolidated financials.

These segments are grouped based on geography and reflect how we currently monitor and report the results of the business to the Chief Executive Officer who is our chief operating decision maker, or CODM, Chief Operating Officer - United States, Chief Operating Officer - Australia and the Group Chief Financial Officer. Factors affecting and differentiating the financial performance of each of these two reportable segments generally include coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. We believe this method of segment reporting reflects the way our business segments are currently managed, resources are allocated and the way the performance of each segment is evaluated. The two segments consist of similar operating activities as each segment produces similar products.

Diversification

We have 100% ownership over all four of our operating mines, allowing us full control over all operating decisions. This control is critical during times of crisis, such as the ongoing COVID-19 pandemic, and it allowed us to react swiftly and decisively to temporarily idle our U.S. operating mines in response to a quick, sharp and unprecedented contraction in demand from Europe, Brazil and North America during the first half of 2020. On June 1, 2020, we resumed production at the Buchanan and Logan mines in the U.S. The Greenbrier mine remains idle and is currently held for sale.

The below charts show run-of-mine, or ROM, production and saleable production for our Australian Operations and our U.S. Operations for the years ended December 31, 2021, 2020 and 2019.

We benefit from a geographically diverse asset base, in Australia and the United States, with access to multiple transportation infrastructure options, including key rail and port infrastructure, providing access to both seaborne export and domestic markets. We have access to the key major markets in both the Atlantic and Pacific basins, and our wide footprint provides flexibility to respond quickly to changes in global market demands.

The low cost nature of our assets is a function of the quality of the assets and the available mine infrastructure to extract our reserves efficiently. We believe being geographically diverse allows us to sell our products to our customers in a number of countries. This allows the sales team to leverage these relationships to provide value added solutions like blends with third parties, which is margin accretive.

Our production is diversified across high quality products, such as hard coking coal, or HCC, semi coking coals, or SCC, and pulverized coal injection, or PCI, coal from our Australian Operations, and significant production of HCC, comprising high volatile content, or High-Vol, (including sub-category A of High-Vol, or HVA, and

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sub-category B of High-Vol, or HVB), coal with medium volatile content, or Mid-Vol, and coal with low volatile content, or Low-Vol, coals from our U.S. Operations. This broad product range supports a wide variety of customer requirements and various blending opportunities, being valued for its attractive coke-making characteristics.

We have a dedicated global marketing team that generates direct sales for our Met coal. Our customer base spans across a full spectrum of key global markets. We sell directly to a number of large, high-quality and well-known companies in the steel industry globally. Many of our core customers have been our longstanding customers for over 20 years, and source our products as essential base load, which translates into a long history of contract renewal for such customers. We are a major supplier to tier one steel mills in Japan, South Korea, Taiwan, India, Europe, Brazil, North America and China. Given the quality of our diverse customer base, we believe the demand for our products is insulated across all stages of the commodity cycle. This flexibility is reflected in our ability to take advantage of current favorable pricing into China out of the United States.

2021 Coronado’s coal trade flows

Overview of Australian Operations—Curragh

Curragh is located in Queensland’s Bowen Basin, one of the world’s premier Met coal regions. Curragh has been operating since 1983, and produces a variety of high-quality, low-ash Met coal products. We believe our HCC product is recognized by steelmakers for its low-ash content, consistency of quality and favorable coking attributes. We believe that our SCC products are similarly valued, in particular for their low wall pressure, which makes them suitable for stamp charging coke ovens, and our PCI coal at Curragh is recognized by steelmakers

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for its low phosphorus and sulphur content. These Met coal products are exported globally to a diverse customer base located primarily in Asia. Curragh also produces thermal coal. The thermal coal produced at Curragh is primarily sold domestically under a long-term contract to Stanwell, with a limited amount being exported.

Revenues from our Australian Operations represented 61.2% of our total revenue for the year ended December 31, 2021. See Item 2. “Properties” for more information regarding Curragh.

For the year ended December 31, 2021, 72.3% of the total volume of coal sold by our Australian Operations was Met coal and 27.7% of the total volume of coal sold by our Australian Operations was thermal coal, the majority of which is sold to Stanwell. For the year ended December 31, 2021, Curragh sold 8.0 MMt of Met coal into the seaborne coal markets. The majority of customers purchase multiple grades or products and have purchased Curragh coal continuously through all stages of the coal/commodity pricing cycle. Curragh’s Met coal is typically sold on annual contracts negotiated by our Australian Operations’ sales managers, with pricing agreed to bilaterally or with reference to benchmark indices or spot indices. Our Australian Operations have maintained a high level of contract coverage against planned production. In 2021, approximately 90% of Curragh’s Met coal export sales were made under term contracts (with the balance sold on framework contracts that do not involve a binding commitment to supply, or in the spot market).

Overview of U.S. Operations—Buchanan and Logan

Our producing mining properties in the United States are located in the CAPP region, specifically in Virginia and West Virginia, which is a highly-developed, active, coal-producing region. Met coal produced by our U.S. Operations is consumed regionally by North American steel producers or exported by seaborne transportation to steel producers (primarily in Asia, Europe and South America). The U.S. Operations also produce small quantities of thermal coal that is extracted in the process of mining Met coal, which is sold predominantly to global export markets, as well as within North America. We believe that many regard Met coal from the CAPP region (where our U.S. Operations are located) to be of the highest quality in the world owing to its generally low-ash and sulphur content. Our U.S. Operations offer a range of Met coal products, with significant production of HCC, comprising High-Vol (including HVA and HVB), coal with Mid-Vol, and coal with Low-Vol.

Sales from our U.S. Operations to export markets are typically priced with reference to a benchmark index. We generally sell our seaborne coal through intermediaries Free on Rail (Incoterms 2010), or FOR., and, therefore, our realized price on FOR sales does not include transportation to the seaborne port or costs to transload into a vessel. Consistent with seaborne sales, sales to North American customers are generally sold on a FOR. basis where the customer arrangers for and incurs the cost of transportation to their facility.

A portion of our sales is sold to North American steel and coke producers on annual contracts at fixed prices that do not fluctuate with the benchmark index. The fixed-price nature of these annual contracts provides us with visibility on our future revenues, as compared to spot sales or sales priced with reference to a benchmark index. For 2022, we have entered into annual contracts to sell approximately 2.9 MMt Met coal with North American steel and coke producers. During periods of stable and rising prices, we strive to take advantage of the spot market. Spot export contracts are negotiated throughout the year. Revenues from our U.S. Operations, in the

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aggregate, represented 38.8% of our total revenue for the year ended December 31, 2021. See Item 2. “Properties” for more information regarding Buchanan, Logan and the other mining properties that compose our U.S. Operations.

For the year ended December 31, 2021, 97.2% of the total volume of coal sold by our U.S. Operations was Met coal and 2.8% was thermal coal. We sold 73.9% of total Met coal from our U.S. Operations into the seaborne Met coal markets for the year ended December 31, 2021.

The Greenbrier mine remains idled since April 1, 2020, following the 2020 economic downturn and decline in demand induced by COVID-19 and is classified as held for sale in our Consolidated Balance Sheets.

Customers

We sell most of our coal to steel producers, either directly or through intermediaries, such as brokers. We also sell thermal coal to electricity generators either directly or through intermediaries such as brokers. Major consumers of our seaborne Met coal in 2021 were located in India, China, Japan, South Korea, Taiwan, Brazil and Europe. These consumers are all major global steel or Met coke producers. The majority of our sales are made under contracts with terms of typically one year or on a spot basis.

Tata Steel

Our U.S. Operations and Australian Operations are parties to a Long Term Coal Sale and Purchase Agreement with Tata Steel, or the Tata Steel Long Term Agreement, with a term ending in March 2022. We have commenced negotiations with TATA Steel to extend our long term relationship after the expiry of the current agreement.

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The Tata Steel Long Term Agreement provides for the sale of a minimum of 3.0 MMt of coal per contract year, consisting of certain specific quantities of Hard Coking Coal, or HCC, Semi Coking Coal and pulverized coal injection, or PCI, Coal. Pricing is re-negotiated each quarter, with coal sales priced in reference to benchmark indices. If we fail to agree on a quarterly price, the Tata Steel Long Term Agreement provides for alternative pricing based on historical market prices and the continuance of deliveries until an agreement on pricing can be reached. Coal sold pursuant to the Tata Steel Long Term Agreement is sold Free on Board (Incoterms 2010), or FOB, and the agreement contains industry-standard terms and conditions with respect to delivery, transportation, inspection, assignment, taxes and performance failure.

Xcoal

In 2021, we sold 2.2 MMt of coal to Xcoal Energy Resources LLC, or Xcoal, largely from our U.S. Operations. Coal revenues from Xcoal represented 28.3% of coal revenues from our U.S. Operations. Purchase orders with Xcoal are entered into primarily on an ad hoc (shipment-by-shipment) basis. Xcoal, as well as other customers, typically take ownership of coal upon loading into the rail car (FOR) and are responsible for handling transportation logistics to the port and beyond. From July 1, 2021, we agreed to credit terms with Xcoal, and any sales to Xcoal in excess of the credit amount are made on prepayment, letter of credit or cash on delivery terms.

Stanwell

We are party to contractual arrangements with Stanwell, including a Coal Supply Agreement, or the CSA, and the Curragh Mine New Coal Supply Deed, dated August 14, 2018, or the Supply Deed.

Under the CSA, we deliver thermal coal from Curragh to Stanwell at an agreed price and quantity. Stanwell may vary the quantity of thermal coal purchased each year so the total quantity to be delivered to Stanwell each year cannot be precisely forecast. The coal that we supply to Stanwell constitutes the majority of the thermal coal production from Curragh. Our cost of supplying coal to Stanwell was greater than the price paid by Stanwell for the year ended December 31, 2021.

Under the CSA, we also share part of the revenue earned from export Met coal sales (from particular Tenements (as defined below)) with Stanwell through various rebates. The most material rebate is the export price rebate, which is linked to the realized export coal price for a defined Met coal product, as follows:

•For the first 7.0 MMtpa of export coal sales: when the 12-month trailing, weighted-average realized export coal price of Reference coal exceeds the Tier 1 Rebate Coal Floor Price, we pay a rebate of 25% of the difference between the realized export coal price and the Tier 1 Rebate Coal Floor Price.

•For export coal sales above 7.0 MMtpa: when the 12-month trailing, weighted-average realized export coal price of Reference coal exceeds the Tier 2 Rebate Coal Floor Price, we pay a rebate of 10% of the difference between the realized export coal price and the Tier 2 Rebate Coal Floor Price.

The CSA also provides for:

•a tonnage rebate to Stanwell per Mt on the first 7.0 MMtpa of export coal sales and on export coal sales above 7.0 MMtpa; and

•a rebate on run-of-mine, or ROM, coal mined in the Curragh “Pit U East Area.”

The total Stanwell rebate for the year ended December 31, 2021, was $55.4 million and has been included in the consolidated statements of operations included elsewhere in this Annual Report on Form 10-K.

The Supply Deed grants us the right to mine the coal reserves in the Stanwell Reserved Area, or the SRA. In exchange, we agreed to certain amendments to the CSA and to enter into a New Coal Supply Agreement, or the NCSA upon the expiration of the CSA (which is expected to occur in 2027). On July 12, 2019, we entered into the NCSA with Stanwell. From the earlier of the expiry of the CSA, the date of termination of the CSA, and January 1, 2029, we will continue to supply thermal coal to Stanwell under the NCSA. The term of the NCSA is expected to be 10 years, and Coronado will supply to Stanwell 2 million ‘Tonnes Equivalent’ of thermal coal per annum (based on a nominal gross calorific value of 25.6GJ) at a fixed contract price that varies in accordance with agreed formulae, inclusive of all statutory charges and royalties in respect of coal sold and delivered under

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the NCSA. The export rebates which were payable under the CSA are not payable during the term of the NCSA. The supply term, the contract tonnage and the contract price under the NCSA are subject to adjustment in accordance with a financial model agreed between Stanwell and us. In summary, we have agreed that the total value of the discount received by Stanwell on coal supplied to it under the NCSA should (by the expiry date of the NCSA) be equal to the net present value of A$210 million as at the date of the Supply Deed. The net present value of the deferred consideration was $230.5 million as of December 31, 2021. On January 18, 2021, the Option Coal Supply Agreement, or the OCSA, contemplated by clause 5 of the NCSA was entered into, in respect of the supply of certain additional coal to Stanwell during the term of the NCSA.

See Item 1A. “Risk Factors—Risks related to the Supply Deed with Stanwell may adversely affect our financial condition and results of operations.”

Transportation

Coal produced at our mining properties is transported to customers by a combination of road, rail, barge and ship. See Item 2. “Properties” for descriptions of the transportation infrastructure available to each of our mining properties. Rail and port services are typically contracted on a long-term, take-or-pay basis in Australia, while these contracts are typically negotiated on a quarterly basis in the United States. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information on our take-or-pay obligations.

Australian Operations

Our Australian Operations typically sell export coal FOB, with the customer paying for transportation from the outbound shipping port. The majority of Curragh’s export Met coal is railed approximately 300 kilometers to the Port of Gladstone for export via two main port terminals, RG Tanna Coal Terminal, or RGTCT, and Wiggins Island Coal Export Terminal, or WICET. Curragh also has capacity available to stockpile coal at the Port of Gladstone. For sales of thermal coal to Stanwell, Stanwell is responsible for the transport of coal to the Stanwell Power Station.

Rail Services

Curragh is linked to the Blackwater rail line of the Central Queensland Coal Network, or CQCN, an integrated coal haulage rail system owned and operated by Aurizon Network Pty Ltd., or Aurizon Network. Curragh has secured annual rail haulage capacity of up to 12.0 MMtpa (plus surge capacity) under long-term rail haulage agreements with Aurizon Operations Limited, or Aurizon Operations, and Pacific National Holdings Pty Limited, or Pacific National.

The RGTCT Coal Transport Services Agreement with Aurizon Operations is for 8.5 MMtpa of haulage capacity to RGTCT. Curragh pays a minimum monthly charge (components of which are payable on a take-or-pay basis), which is calculated with reference to the below-rail access charges, haulage/freight charges, a minimum annual tonnage charge and other charges. The RGTCT Coal Transport Services Agreement terminates on June 30, 2030.

The Coal Transport Services Agreement with Pacific National is for 1.0 MMtpa of haulage capacity to RGTCT. Curragh pays a minimum monthly charge (components of which are payable on a take-or-pay basis), which is calculated with reference to the below-rail access charges, haulage/freight charges, a minimum annual tonnage charge and other charges. The Coal Transport Services Agreement with Pacific National terminates on July 31, 2029.

The Wiggins Island Rail Project, or WIRP, Transport Services Agreement with Aurizon Operations is for 2.0 MMtpa of capacity to WICET. This contract is effectively 100% take-or-pay (for a portion of the rail haulage and all capacity access charges). This agreement expires on June 30, 2030.

Port Services

Curragh exports coal through two terminals at the Port of Gladstone, RGTCT and WICET. At RGTCT, we and Gladstone Port Corporation Limited, or GPC, are parties to a coal handling agreement that expires on June 30, 2030. The agreement may be renewed at our request and, subject to certain conditions, GPC is required to agree

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to the extension if there is capacity at RGTCT to allow the extension. We currently have the right to export between 7.7 MMtpa and 8.7 MMtpa at our nomination on a take-or-pay basis.

We have a minority interest in WICET Holdings Pty Ltd, whose wholly-owned subsidiary, Wiggins Island Coal Export Terminal Pty Ltd, or WICET Pty Ltd, owns WICET. Other coal producers who export coal through WICET also hold shares in WICET Holdings Pty Ltd. In addition, we and the other coal producers (or shippers) have take-or-pay agreements with WICET Pty Ltd and pay a terminal handling charge to export coal through WICET, which is calculated by reference to WICET’s annual operating costs, as well as finance costs associated with WICET Pty Ltd’s external debt facilities. Our take-or-pay agreement with WICET Pty Ltd, or the WICET Take-or-Pay Agreement, provides Curragh with export capacity of 1.5 MMtpa. The WICET Take-or-Pay Agreement is an “evergreen” agreement, with rolling ten-year terms. If we inform WICET Pty Ltd that we do not wish to continue to roll the term of the WICET Take-or-Pay Agreement, the term would be set at nine years and the terminal handling charge payable by us would be increased so that our proportion of WICET Pty Ltd’s debt is amortized to nil by the end of that nine-year term.

Under the WICET Take-or-Pay Agreement, we are obligated to pay for that capacity via terminal handling charges, whether utilized or not. The terminal handling charge payable by us can be adjusted by WICET Pty Ltd if our share of WICET Pty Ltd’s operational and finance costs increases, including because of increased operational costs or because another shipper defaults and has its capacity reduced to nil. The terminal handling charge is subject to a financing cap set out in the terminal handling charge methodology and has already been reached and is in force. If another shipper defaults under its take-or-pay agreement, each remaining shipper is effectively proportionately liable to pay that defaulting shipper’s share of WICET Pty Ltd’s costs going forward, in the form of increased terminal handling charges.

If we default under the WICET Take-or-Pay Agreement, we would be obligated to pay a termination payment to WICET Pty Ltd. The termination payment effectively represents our proportion of WICET Pty Ltd’s total debt outstanding, based on the proportion of our contracted tonnage to the total contracted tonnage of shippers at WICET at the time the payment is triggered. Shippers can also become liable to pay the termination payment where there is a permanent cessation of operations at WICET. Since WICET began shipping export tonnages in April 2015, four WICET Holdings Pty Ltd shareholders have entered into administration and Take-or-Pay Agreements subsequently terminated, resulting in the aggregate contracted tonnage of shippers decreasing from 27 MMtpa to 15.5 MMtpa.

Under the WICET Take-or-Pay Agreement, we are required to provide security (which is provided in the form of a bank guarantee). The amount of the security must cover our estimated liabilities as a shipper under the WICET Take-or-Pay Agreement for the following twelve-month period. If we are in default under the WICET Take-or-Pay Agreement and are subject to a termination payment, WICET Pty Ltd can draw on the security and apply it to amounts owing by us. See Item 1A. “Risk Factors—Risks related to our investment in WICET may adversely affect our financial condition and results of operations” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information on our take-or-pay obligations.

During 2019, Coronado entered into an Agreement with Washpool Coal Pty Ltd for assignment of their WICET capacity of 1.6 MMt per annum, on a take-or-pay basis for a term to June 30, 2022, at market rates.

U.S. Operations

Our U.S. Operations’ domestic contracts are generally priced FOR at the mine with customers bearing the transportation costs from the mine to the applicable end user. For direct sales to export customers, we hold the transportation contract and are responsible for the cost to the export facility, and the export customer is responsible for the transportation/freight cost from the export facility to the destination. A portion of our U.S. export sales are made through Xcoal and other intermediaries. For these sales, Xcoal or the intermediary typically take ownership of the coal as it is loaded into the railcar. The intermediary is responsible for the rail transportation and port costs.

Rail Services

Our U.S. Operations are served by Northfork Southern and CSX Transportation railroads. In 2021, we shipped approximately 95.4% of our total shipments via rail from our U.S. mining properties.

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Northfork Southern railroad serves our Buchanan mining property and transports Buchanan’s coal to Lamberts Point Coal Terminal Pier 6 and to CNX Marine Terminal for export customers and to our domestic customers either directly or indirectly via inland river dock facilities where the coal is transloaded on to barges and then transported to the customer facilities.

CSX Transportation railroad serves our Logan and Greenbrier mining properties. CSX transports Logan and Greenbrier’s coal to Kinder Morgan Pier IX Terminal or CNX Marine Terminal or Dominion Terminal Associates (DTA) for export customers and either directly to the customers or to inland river dock facilities for domestic customers.

Port Services

Norfolk Southern’s Lamberts Point Coal Terminal Pier 6 is the largest coal loading facility in the Northern Hemisphere with 48 million tons of annual export capacity and is the main terminal at the Lamberts Point located in Norfolk, Virginia. Kinder Morgan’s Pier IX is a coal export terminal with an annual export capacity of 16 million tons located in the Port of Hampton Roads in Newport News, Virginia.

Our U.S. Operations have dedicated inventory capacity and a take or pay obligation to transload one million net tons per year through Kinder Morgan’s Pier IX Terminal, which expires at the end of March 2024. Our U.S. Operations also have alternate port access through CNX Marine Terminal which is a transshipping terminal at the Port of Baltimore owned by CONSOL Energy.

DTA Terminal is a coal export terminal located in the Port of Hampton Roads in Newport News, Virginia. DTA Terminal is 65% owned by Alpha Metallurgical Resources and 35% by Arch Coal and has annual export capacity of 22 MMt.

Kanawha River Terminal is a Norfolk Southern/CSX-served coal terminal located on the Ohio River at mile marker 314.5, Ceredo, West Virginia.

Suppliers

The principal goods we purchase in support of our mining activities are mining equipment, replacement parts, diesel fuel, natural gas, ammonium-nitrate and emulsion-based explosives, off-road tires, steel-related products (including roof control materials), lubricants and electricity. As a general matter, we have many well-established, strategic relationships with our key suppliers of goods and do not believe that we are dependent on any of our individual suppliers.

We also depend on several major pieces of mining equipment and facilities to produce and transport coal, including, but not limited to, longwall mining systems, continuous miners, draglines, dozers, excavators, shovels, haul trucks, conveyors, coal preparation plants, or CPPs, and rail loading and blending facilities. Obtaining and repairing these major pieces of equipment and facilities often involves long lead times. We strive to extend the lives of existing equipment and facilities through maintenance practices and equipment rebuilds in order to defer the requirement for larger capital purchases. We use our global leverage with major suppliers to ensure security of supply to meet the requirements of our active mines. See Item 2. “Properties” for more information about operations at our mining properties.

We use contractors and other third parties for exploration, mining and other services, generally, and are reliant on a number of third parties for the success of our current operations and the advancement of our development projects. See Item 1A. “Risk Factors—Our profitability could be affected adversely by the failure of suppliers and/or outside contractors to perform.”

Thiess Mining Services Contract

We currently use Thiess Pty Ltd, or Thiess, as our primary mining contractor for our Australian Operations.

We are party to a long-term mining contract with Thiess to provide hydraulic excavator overburden and coal mining, pit dewatering, run of mine rehandling services and maintenance of Coronado owned heavy mobile equipment at the Curragh North operation until December 31, 2025, referred to as Part A Services; and to provide rope shovel overburden removal using Coronado’s rope shovel and Thiess supplied ultra-class truck services

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until March 31, 2022, referred to as Part B Services. We are currently working towards finalizing agreements with Thiess to take on management and operation of additional mining fleets, including the rope shovel and ultra-class trucks currently included in the Part B Services. These new agreements are expected to commence following the expiry of the Part B Services.

Competition

We operate in a competitive environment. We compete with domestic and international coal producers, traders and brokers. We compete on price, coal quality, transportation, optionality, reputation and reliability. Demand for Met coal and the prices that we will be able to obtain for our Met coal are highly competitive and are determined predominantly by world markets, which are affected by numerous factors, including: general global, regional and local economic activity; changes in demand for steel and energy; industrial production levels; short-term constraints, including weather incidents; changes in the supply of seaborne coal; technological changes; changes in international freight or other transportation infrastructure rates and costs; the costs of other commodities and substitutes for coal; market changes in coal quality requirements; government regulations which restrict, or increase the cost of, using coal; tariffs imposed by countries, including the United States and Australia, on the import of certain steel products and any retaliatory tariffs by other countries; and tax impositions on the resources industry, all of which are outside of our control. In addition, coal prices are highly dependent on the outlook for coal consumption in large Asian economies, such as China, Japan, South Korea and India, as well as any changes in government policy regarding coal or energy in those countries.

In developing our business plan and operating budget, we make certain assumptions regarding future Met coal prices, coal demand and coal supply. The prices we receive for our Met coal depend on numerous market factors beyond our control. Accordingly, some underlying coal price assumptions relied on by us may materially change and actual coal prices and demand may differ materially from those expected. Our business, operating and financial performance, including cash flows and asset values, may be materially and adversely affected by short- or long-term volatility in the prevailing prices of our products.

Competition in the coal industry is based on many factors, including, among others, world supply price, production capacity, coal quality and characteristics, transportation capability and costs, blending capability, brand name and diversified operations. We are subject to competition from producers in Australia, the United States, Canada, Russia, Mongolia and other coal producing countries. See Item 1A. “Risk Factors—We face significant competition, which could adversely affect profitability.”

Environmental Sustainability

We are focused on extracting high quality Met coal in an environmentally responsible way. Coal mining is one of the most environmentally regulated industries in the world, and it is vital that we consistently meet or exceed relevant regulatory standards.

We are subject to various environmental laws, regulations and public policies in Australia and the United States. Managing our environment and climate change risks is a key component of our corporate strategy and it is integrated into all stages and areas or our daily operations. We seek to minimize our environmental impact and ensure we meet or exceed our legislative and regulatory environmental obligations.

Coronado’s environmental sustainability initiatives and strategy are discussed further in our 2020 Sustainability Report, which can be found on our website at www.coronadoglobal.com/sustainability/. Nothing on our website, including our 2020 Sustainability Report or sections thereof, shall be deemed incorporated by reference into this Annual Report on Form 10-K. Our 2021 Sustainability Report is expected to be available in May 2022.

Climate change

While our operations are recognized as vital contributors to the communities and economies in which we operate, we acknowledge that our mining activities create greenhouse gas, or GHG, emissions. Climate change is one of the most significant issues for the steel industry and the industry has made significant reductions in GHG emissions by improving energy efficiency and using new technologies. Where possible, we are continuing to identify and implement GHG emissions and energy reduction opportunities across our business, whilst monitoring climate related risks and the sustainability of our operations. We are committed to working with other industry participants to support, develop and introduce new coal production and energy-generation technologies, that help reduce the environmental impact while continuing to meet global energy and steel demands.

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Our Australian Operations disclose GHG scope 1 and 2 emissions annually to the Clean Energy Regulator under the National Greenhouse and Energy Reporting Scheme. Our U.S. Operations disclose GHG scope 1 and 2 emissions, including fugitive emissions (methane), for the facilities required to report their emissions annually to the United States Environmental Protection Agency.

Our operations are currently focused on implementing reporting improvements, identifying opportunities for reducing emissions intention on a per ton of production basis and benchmarking ourselves against our peer group prior to setting any emission reduction targets. We are also evaluating a range of potential projects that could have a positive impact on our emissions profile including assessing options for a “behind the meter” type solar farm and opportunities to harvest incidental coal seam gas (fugitive emissions - Scope 1) to either generate electric power on site at Curragh or to use as a partial replacement for diesel fuel.

Increased public concern may result in additional regulatory risks as new laws and regulations aimed at reducing GHG emissions come into effect in the jurisdictions in which we operate. Any legislation that limits or taxes GHG emissions could adversely impact our growth, increase our operating costs, or reduce demand for our coal.

With respect to physical climate risks, our operations may be impacted by weather-related events potentially resulting in lost production, supply chain disruptions and increased operating costs, which could have a material adverse impact on our financial results of operations.

On November 13, 2021, the Glasgow Conference of Parties 26, or COP26, agreed on the language around fossil fuels in the final Glasgow Climate Pact. A call on countries to “phase out” coal power was changed to “phase down of unabated coal power”, that is coal power that does not include the capture and storage of carbon dioxide emission. 190 countries have now agreed to phase down coal power. 65 countries have now committed to coal phase out, including more than 20 new commitments at COP26. 48 countries are members of the Powering Past Coal Alliance, or PPCA. All major coal financing countries have committed to end international coal finance by the end of 2021. As a result, Glasgow COP26 is expected to accelerate the trend of higher finance and insurance costs for coal miners and coal-fired power generators. The agreement on carbon accounting has also made global trade in carbon more likely, eventually accelerating the competitiveness of low-carbon solutions in the power and steel sectors.

Under the Paris Agreement, Australia must submit emissions reduction commitments known as Nationally Determined Contributions, or NDCs, which includes its national targets. Australia’s first NDC commitments are:

•2015 NDC: committed to reduce emissions by 26 to 28% below 2005 levels by 2030.

•2020 NDC update: affirmed the 2030 target, outlined Australia’s practical, technology-led approach to emission reductions, include new actions and measures since 2015.

•2021 NDC update: committed to net zero emissions by 2050, inscribed low emissions technology stretch goals, affirmed the 2030 target, and reported 2021 projections results showing Australia is on track to exceed this target by up to 9 percentage points.

Australia will submit its second NDC to the United Nations Framework Convention on Climate Change, or UNFCCC, in 2025.

Human Capital Disclosures

Our ability to attract and retain skilled, motivated and engaged employees is an essential part of our business. Investing in the skill and capabilities of our people will underwrite our long-term growth and sustainability. In both Australia and United States, we operate in regional locations with highly competitive labor markets. In each location, we are creating a high-performing workforce with a talent pipeline for future leaders, including succession planning for critical roles. To achieve this, we continue to create a culture that welcomes and values all people and where our core values of collaboration, accountability, respect and excellence are demonstrated in everything that we do.

We had 1,577 employees as of December 31, 2021. In addition, as of December 31, 2021, there were 1,848 contractors supplementing the permanent workforce, primarily at Curragh.

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As of December 31, 2021, approximately 12% of our total employees, all at our Australian Operations, were covered by a single, federally-certified collective Enterprise Agreement, or the EA, for specified groups of mining and maintenance employees. The EA links us with; the Automotive, Food, Metals, Engineering, Printing and Kindred Industries Union; the Construction, Forestry, Maritime, Mining and Energy Union; the Communications, Electrical, Electronic, Energy, Information, Postal, Plumbing and Allied Services Union of Australia; and our employees performing mining and operational functions. In May 2019, the Australian Fair Work Commission approved the Curragh Mine Enterprise Agreement 2019. This EA has a nominal expiration date of May 26, 2022 and will remain in place until replaced or terminated by the Fair Work Commission. Our U.S. Operations employ a 100% non-union labor force.

Safety

Our employees and contractors are our most valuable assets and we consider their safety our number one priority. Safety is essential to all business functions and is never to be compromised, under any circumstance. The health and safety of our people is reinforced every day through our culture, behaviors, training, communication and procedures.

We manage safety and health through continuous improvement efforts and the implementation of practices and procedures that address safety risks in full compliance with the legal and regulatory frameworks of both the United States and Australia. We empower our people to consistently strive to have a safety mindset, and act by applying, managing and monitoring effective controls to prevent adverse outcomes with all activities and operations. Our programs are intended to reinforce our position that safety and health should always be front of mind for all employees and contractors. These programs are assessed on a regular basis to ensure they continue to be fit for purpose. We have robust training programs and strategic initiatives in place to ensure workers are informed about health and safety matters, including coal workers’ pneumoconiosis, or CWP, silicosis, hearing loss, and other occupational illnesses. In addition, we conduct sampling and health checks with our workers in line with health and safety legislative requirements.

We recognize that the mental health and wellbeing of our employees is equally as important as physical health and acknowledge that the pandemic has had a significant impact on the mental health of communities and societies across the world. In 2021, we introduced an Employee Assistance Program, or EAP, in the U.S. and increased the promotion of the EAP service in Australia which has been in operation for a number of years. Both programs offer employees and their families confidential and free counselling services

Safety performance is monitored through physical observations from both internal and external parties and through the reporting of key metrics. Safety performance is assessed monthly against internal goals and on a quarterly basis is benchmarked against our peers within the mining industry.

We set targets for safety interactions which is a process where employees observe a risk behavior and provide immediate feedback if it is deemed, or has the potential to be, unsafe. This is monitored by management daily through safety meetings, site visits, employee discussions, and management observations. The process allows for greater empowerment, innovation and employee input into the mining process.

On November 21, 2021, one of our employees at the Curragh mine, was fatally injured while working in the dragline operations. The Resources Safety & Health Queensland Inspectorate subsequently issued directives requiring isolation of the accident site and temporary suspension of dragline operations at Curragh until the Inspectorate and the Company were satisfied that these activities could recommence safely. Work at the mine recommenced gradually from November 24, 2021, following return to work safety sessions involving all workers on site. On December 10, 2021, the Inspectorate allowed dragline operations to recommence. We have complied with all requirements of the Inspectorate in relation to the incident.

The 12-month rolling average Total Reportable Injury Frequency Rate (“TRIFR”) as of December 31, 2021 for our Australian Operations was 3.07 and the Total Reportable Incident Rate (“TRIR”) for 12-month rolling average as of December 31, 2021 for our U.S. Operations was 2.51. As indicated in the graphs below, our Australian Operations outperformed the Queensland industry average in 2020 and 2021 and our U.S. Operations outperformed the U.S. national average in 2020 and 2021. We strive to ensure that we continue to provide a safe operating environment for all employees and contractors.

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The safety and wellbeing of our workforce remains our highest priority and we continue to manage the potential threat of COVID-19 at our mines and offices. The Company’s COVID-19 Steering Committee, formed in 2020, has successfully monitored the effect of the pandemic across our Australian Operations and U.S. Operations and continues to implement proactive preventative measures to ensure the safety and well-being of employees and contractors. See “—COVID-19” above for more information.

Workforce composition and diversity

Our values (CARE – Collaboration, Accountability, Respect, Excellence) guide our policies, processes and actions as they relate to all workforce interactions and people related initiatives. As part of these values and to enable our people to excel within the workplace we are building a diverse and inclusive workforce, where unique viewpoints are heard, valued and respected. We believe this directly impacts the safety and productivity of our people. Our employees are trained to recognize and mitigate potential biases towards others. We continue to invest in training initiatives to challenge hiring managers’ unconscious bias and preconceptions. These initiatives have equipped our leaders with knowledge and tools to identify and challenge stereotypes and biased decision making. It also led to the review of policies and processes that may have inhibited the hiring and promotion of certain people. This included reviewing the wording used in job advertisements and challenging what has historically been regarded as essential experience to ensure that people entering the industry, or who have taken a career break, are not unintentionally disadvantaged.

We invest in training and development programs for both our new and long-serving employees. Investing in graduate recruitment, traineeships and internship programs through partnerships with leading education institutions has been central to accessing talent and building our brand. Further, our internal leadership development enhances succession planning and the transfer of skills and knowledge across our business.

As at December 31, 2021:

•in the United States, close to 9% of Senior Managers were female.

•in Australia, 28% of employees at a General Manager, Senior Manager and Senior Professional level were female, an increase of approximately 4% from December 31, 2020.

•in Australia, 33% of new employees were female.

•7% of our global workforce were female.

•61% of all employees were between the ages of 30 and 50 year.

We supported 2 of our female employees in Australia to participate in the Women’s Mentoring Program run by Women in Mining and Resources Queensland (WIMARQ). This program was created in response to identified demand for formal mentoring for women working in Queensland’s minerals and energy sectors and to improve retention and progression of women in our sector. It provides a structured, sustainable mentoring process that

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supports women through career guidance and direction by sharing experiences, developing goals and forging exceptional mentoring relationships beyond the program’s duration.

Attracting and retaining the right people

We continued to focus our efforts on recruiting trainees and other entry level roles. We have also implemented the following initiatives:

•Comprehensive training, performance and leadership development programs.

•Competitive and flexible remuneration structure.

We have continuous improvement and feedback mindset in relation to further promoting employee engagement and motivation. Across our business there is concerted effort to develop leadership skills, foster and inclusive working environment, and assist managers improve engagement and productivity.

In 2021, our total rolling turnover rate was 27.9% and 18.4% and our voluntary departure rolling turnover rate was 17.3% and 15.4%, in Australia and the U.S., respectively. In 2020, our total rolling turnover rate was 14.3% and 36.5% and our voluntary departure rolling turnover rate was 8% and 11%, in Australia and the U.S., respectively.

Regulatory Matters—Australia

Our Australian Operations are regulated by the laws and regulations of the Commonwealth of Australia, or Cth, the State of Queensland, or Qld, and local jurisdictions. Most environmental laws are promulgated at the state level, but the Australian federal government has a role in approval of actions which have national environmental significance. In Queensland, the environmental laws relevant to coal mining include development legislation, pollution, waste, ecosystem protection, cultural heritage and native title land contamination and rehabilitation legislation. In addition, the Australian federal government regulates foreign investment and export approvals.

Tenements

We control the coal mining rights at Curragh under 14 coal and infrastructure mining leases, or MLs, and three mineral development licenses, or MDLs, granted pursuant to the Mineral Resources Act 1989 (Qld). We refer to the MLs and MDLs at Curragh, collectively, as the Tenements. Renewal of certain Tenements will be required during the mine life of Curragh and the Queensland government can vary the terms and conditions on renewal. There are a number of existing mining and petroleum tenements which overlap with the Tenements. The priority, consent and coordination requirements under the Mineral Resources Act 1989 (Qld), the Petroleum and Gas (Production and Safety) Act 2004 (Qld) and Mineral and Energy Resources (Common Provisions) Act 2014 (Qld) (as relevant) may apply with respect to those overlaps. Extensive statutory protocols govern the relationships between co-existing mining and exploration rights and these protocols are largely focused on encouraging the overlapping tenement holders to negotiate and formulate arrangements that enable the co-existence of their respective interests. See Item 2. “Properties” for more information regarding the Tenements.

Mineral Resources Act 1989 (Qld)

The Mineral Resources Act 1989 (Qld) and the Mineral and Energy Resources (Common Provisions) Act 2014 (Qld), together, provide for the assessment, development and utilization of mineral resources in Queensland to the maximum extent practicable, consistent with sound economic and land use management. The Mineral Resources Act 1989 (Qld) vests ownership of minerals, with limited exceptions, in the Crown (i.e., the state government). A royalty is payable to the Crown for the right to extract minerals. The Mineral Resources Act 1989 (Qld) creates different tenures for different mining activities, such as prospecting, exploring and mining. A ML is the most important tenure, as it permits the extraction of minerals in conjunction with other required authorities. The Mineral Resources Act 1989 (Qld) imposes general conditions on a ML.

A person who is the holder of a ML must keep the records necessary to enable the royalty payable by the person to be ascertained. The royalty payable on the value of coal sold, disposed of or used (post October 1, 2012) is as set out below:

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•if the average price per Mt is A$100 or less: 7%;

•if the average price per Mt is more than A$100 but less than or equal to A$150: 7% on the first A$100 and 12.5% on the balance of the average price per Mt; and

•if the average price per Mt is A$150 or more: 7% on the first A$100, 12.5% on the next A$50 and 15% on the balance of the price per Mt.

The royalty payable for coal sold, disposed of or used in a return period is then calculated by multiplying the royalty rate by the value of the coal. Queensland Revenue Office Royalty Ruling MRA001.1 contains details on the costs that can (and cannot) be deducted when calculating the applicable royalty and the method for determining the value of the coal. Where there is a change in legislation or case law that affects the content of a royalty ruling, the change in the law overrides the royalty ruling—i.e., the Commissioner will determine the royalty liability in accordance with the changed law. See Item 2. “Properties” for a discussion of the royalties currently applicable to Curragh.

Mining Rehabilitation (Reclamation)

Mine closure and rehabilitation risks and costs are regulated by Queensland state legislation.

Amongst other things, an Environmental Authority Holder, or EA Holder, must provide the Queensland State Government with financial assurance for the purpose of drawing upon in the event that an EA Holder defaults on its obligations to rehabilitate the mine site.

The Mineral and Energy Resources (Financial Provisioning) Act 2018 (Qld), or the Financial Provisioning Act establishes a financial provisioning scheme, or the Scheme, from which the Department of Environment and Science, or the DES, sources funds to rehabilitate and remediate land subject to mining.

Under the Financial Provisioning Act, all mine operators are required to make a submission to the DES in respect of an Estimated Rehabilitation Cost, or ERC, for the mine site. The ERC is determined using the DES-approved ERC calculator. Using this information, the DES sets the ERC for the mine. The DES provides the ERC to the manager of the Scheme, or the Scheme Manager. The Scheme Manager undertakes a risk assessment of the mine, which is based upon independent advice from a scheme risk advisor. It includes detail on the mine operator’s financial soundness and credit rating, characteristics of the mining operation (e.g., life of mine, or LOM, and off-take agreements), rehabilitation history, environmental compliance history and the submission made by the company. Risk categories include high, moderate, low and very low. If the ERC and risk categories are set at moderate, low or very low for a mine, then there is a need to pay an annual contribution based on a small percentage of the ERC to the Scheme. If the category is high, then the operation provides a surety for the whole ERC and possibly a contribution to the Scheme. The risk assessment of the mine and, therefore, the amount of the contribution to the fund is assessed and paid annually in perpetuity, or until a clearance certificate is obtained.

Each year, the Scheme Manager is required to make an Annual Review Allocation to determine whether the mine will provide surety or pay a contribution to the Scheme depending on the value of the ERC relating to applicable environmental authorities, as follows:

1) ERC < A$100,000 - cash surety or bank guarantees

2) ERC = A$100,000 – A$450 million - pay a cash contribution into the Scheme

3) ERC > A$450 million - pay a cash contribution into the Scheme and provide bank guarantees.

Curragh has 2 environmental authorities, or EAs, which are covered by the Scheme, namely EA number EPML00643713 and EA number EPVX00635313. Under the transitional arrangements for the Scheme, Curragh’s existing financial assurance arrangements were deemed to be the ERC for both environmental authority number EPML00643713 and AE number EPVX00635313. In September 2020, Curragh applied for a new ERC in respect of EA number EPML00643713 which applies for the period from 3 November 2020 to 2 November 2022.

In October 2021, the Scheme Manager completed the assessment of the Annual Review Allocation for EA number EPML00643713 and issued an Annual Review Allocation of “Moderate”. The moderate rating resulted in Curragh being obliged to make a financial contribution to the Scheme of 2.75% of the ERC. In January 2022, the Scheme Manager completed an assessment of the Annual Review Allocation for EA number EPVX00635313

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and issued an Annual Review Allocation of “High” in respect of MDL162 requiring Curragh to maintain its historical financial assurance in respect of 100% of the ERC for Environmental Authority Number EPVX00635313.

The Financial Provisioning Act also requires for a Progressive Rehabilitation and Closure Plan, or a PRCP, with respect to mined land. This requirement will be integrated into the existing EA processes for new mines, minimizing the regulatory burden on government and industry. All mining projects carried out under a ML that make a site-specific EA application will be required to provide a PRCP. If approved by the administering authority, a stand-alone PRCP schedule will be given to the applicant together with the EA. The PRCP schedule will contain milestones with completion dates for achieving progressive rehabilitation of the mine site. The Financial Provisioning Act provides transitional arrangements for three years for the application of the PRCP requirement to existing mines. The requirement for a PRCP commenced on November 1, 2019, or the PRCP start date, however all existing mining operations only transition into the PRCP framework once a transition notice is issued by the relevant government department. Curragh has been issued with a transition notice with respect to its PRCP and is required to submit the proposed PRCP to the administering authority by October 21, 2022.

Environmental Protection Act 1994 (Qld)

The primary legislation regulating environmental management of mining activities in Queensland is the Environmental Protection Act 1994 (Qld), or the EP Act. Its objective is to protect Queensland’s environment while allowing for development that improves the total quality of life, both now and in the future, in a way that maintains ecologically sustainable development. Under the EP Act, it is an offense to carry out a mining activity unless the person holds or is acting under an EA for the activity. The EA imposes conditions on a project. It is an offense to contravene a condition of an EA. In addition to the requirements found in the conditions of an EA, the holder must also meet its general environmental duty and duty to notify of environmental harm and otherwise comply with the provisions of the EP Act and the regulations promulgated thereunder. For example, the following are offenses under the EP Act:

•causing serious or material environmental harm;

•causing environmental nuisance;

•depositing proscribed water contaminants in waters and related matters; and

•placing contaminants where environmental harm or nuisance may be caused.

The EA holder must also be a registered suitable operator under the EP Act. We are a registered suitable operator.

We hold EA EPML00643713, which authorizes the mining of black coal, mineral processing, chemical storage, waste disposal and sewage treatment over the 14 MLs at Curragh on certain conditions. Those conditions include requirements in relation to air and water quality, regulated structures (e.g., dams), noise and vibration, waste, land use, rehabilitation and watercourse diversion.

We also hold a range of subsidiary EAs for our Australian Operations. See “—Mining Rehabilitation (Reclamation)” above for more information regarding the Financial Provisioning Act.

Aboriginal Cultural Heritage Act 2003 (Qld)

The Aboriginal Cultural Heritage Act 2003 (Qld) imposes a duty of care on all persons to take all reasonable and practicable measures to ensure that any activity conducted does not harm Aboriginal cultural heritage. Its object is to provide effective recognition, protection and conservation of Aboriginal cultural heritage.

We have obligations relating to Aboriginal cultural heritage with respect to a number of cultural heritage objects and areas located within the area of the Tenements. We work closely with the Aboriginal people to manage the cultural heritage objects, areas or evidence of archaeological significance, within our mining operations. We are party to a Cultural Heritage Management Plan (and associated Cultural Services Agreement) with the Gaangalu Nation People that applies to all of the Tenements. The plan establishes a coordinating committee and sets out the steps to be followed to manage activities that may impact Aboriginal cultural heritage.

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Native Title Act 1993 (Cth)

The Native Title Act 1993 (Cth), or NTA, sets out procedures under which native title claims may be lodged and determined and compensation claimed for the extinguishment or impairment of the native title rights or interests of Aboriginal peoples. Its object is to provide for the recognition and protection of native title, to establish ways in which future dealings affecting native title may proceed and to set standards for those dealings, to establish a mechanism for determining claims to native title and to provide for, or permit, the validation of past acts, and intermediate period acts, invalidated because of the existence of native title.

With respect to MLs and MDLs granted under the Mineral Resources Act 1989 (Qld) on state land where native title has not been extinguished, a principle known as the non-extinguishment principle governs. Broadly, under this principle, native title rights are suspended while the mining tenure, as renewed from time to time, is in force. The grant (or renewal) of a mining tenure in respect of land where native title may exist must comply with the NTA to ensure the validity of the tenure. Registered native title claimants have certain notification, consultation and negotiation rights relating to mining tenures. Where native title is extinguished (i.e., freehold land), the NTA does not apply.

Regional Planning Interests

The Regional Planning Interests Act 2014 (Qld), or the RPI Act manages the impact of resource activities and other regulated activities in areas of the state that contribute, or are likely to contribute, to Queensland’s economic, social and environmental prosperity (e.g., competing land use activities on prime farming land). The RPI Act identifies areas of Queensland that are of regional interest, including strategic cropping areas and strategic environmental areas. Under the RPI Act, conducting a resource activity in an area of regional interest requires a regional interest development approval, unless operating under an exemption. Importantly, pre-existing mining activities being undertaken at the date of the introduction of the legislation are exempt.

We applied for and were granted a regional interest development approval for the “Curragh Expansion Project” (for ML700006, ML 700007 and ML700008), which is subject to regional interest conditions, such as mitigation. Certain protection conditions were also imposed on us with respect to our application for ML 80171 (which has since been granted). These include an obligation to provide mitigation in the event that strategic cropping land is impacted by future operations.

Environmental Protection and Biodiversity Conservation Act 1999 (Cth)

The Environment Protection and Biodiversity Conservation Act 1999 (Cth), or the EPBC Act, provides a federal framework to protect and manage matters of national environmental significance, such as listed threatened species and ecological communities and water resources. In addition, the EPBC Act confers jurisdiction over actions that have a significant impact on the environment where the actions affect, or are taken on, Commonwealth land, or are carried out by a Commonwealth agency.

Under the EPBC Act, “controlled actions” that have or are likely to have a significant impact on a matter of national environmental significance are subject to a rigorous assessment and approval process. A person must not take a “controlled action” unless approval is granted under the EPBC Act. Any person proposing to carry out an “action” that may be a “controlled action” must refer the matter to the Commonwealth Minister for a determination as to whether the proposed action is a controlled action.

On November 2, 2016, the Commonwealth Minister for the Department of the Environment and Energy administering the EPBC Act approved the extension of the existing Curragh mining area to include mining four additional Tenements—ML 700006, ML 700007, ML 700008 and ML 700009 (EPBC Act referral 2015/7508)—as a “controlled action,” on certain conditions. The conditions include requirements in relation to offsets and groundwater.

Mine Health and Safety

The primary health and safety legislation that applies to Curragh are the Coal Mining Safety and Health Act 1999 (Qld) and the Coal Mining Safety and Health Regulation 2001 (Qld), which we refer to, together, as the Coal Mining Safety Legislation.

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Additional legislative requirements apply to operations that are carried on off-site or which are not principally related to coal mining (e.g., transport, rail operations, etc.). The Coal Mining Safety Legislation imposes safety and health obligations on persons who operate coal mines or who may affect the safety or health of others at coal mines. Under the Coal Mining Safety Legislation, the operator of a coal mine must, among other things:

•ensure that the risk to coal mine workers while at the operator’s mine is at an acceptable level;

•audit and review the effectiveness and implementation of the safety and health management system to ensure the risk to persons is at an acceptable level;

•provide adequate resources to ensure the effectiveness and implementation of the safety and health management system;

•ensure the operator’s own safety and health and the safety and health of others is not affected by the way the operator conducts coal mining operations;

•not carry out an activity at the coal mine that creates a risk to a person on an adjacent or overlapping petroleum authority if the risk is higher than an acceptable level of risk;

•appoint a site senior executive for the mine;

•ensure the site senior executive develops and implements a safety and health management system for all people at the mine;

•ensure the site senior executive develops, implements and maintains a management structure for the mine that helps ensure the safety and health of persons at the mine; and

•not operate the coal mine without a safety and health management system for the mine.

We recognize that health and safety are imperative to the ongoing success of our Australian Operations. As the operator at Curragh, we have in place a comprehensive safety and health management system, which includes an emergency response team, to address these legislative requirements. In accordance with the Coal Mining Safety Legislation we have also established an occupational hygiene baseline for dust exposure at Curragh.

Water Act 2000 (Qld)

In Queensland, all entitlements to the use, control and flow of water are vested in the state and regulated by the Water Act 2000 (Qld). Allocations under the Water Act 2000 (Qld) can be managed by a water supply scheme operator, such as SunWater Ltd, which is a Government-owned corporation regulated by the Queensland Competition Authority. We have purchased the required water allocations for Curragh and entered into a suite of related channel and pipeline infrastructure agreements and river supply agreements with SunWater Ltd to regulate the supply of water pursuant to these allocations. See Item 1A. “Risk Factors—In times of drought and/or shortage of available water, our operations and production, particularly at Curragh, could be negatively impacted if the regulators impose restrictions on our water offtake licenses that are required for water used in the CPPs.”

National Greenhouse and Energy Reporting Act 2007 (Cth).

The National Greenhouse and Energy Reporting Act 2007 (Cth) imposes requirements for both foreign and local corporations whose carbon dioxide production, greenhouse gas, or GHG, emissions and/or energy consumption meets a certain threshold to register and report GHG emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the National Greenhouse and Energy Reporting Act 2007 (Cth), and the Department of Environment and Energy is responsible for related policy developments and review.

In accordance with the Emissions Reduction Fund Safeguard Mechanism under this legislation, Curragh has been assigned a baseline for its covered emissions and we must take steps to keep our emissions at or below the baseline or face penalties.

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Labor Relations

Minimum employment entitlements, embodied in the National Employment Standards, apply to all private-sector employees and employers in Australia under the federal Fair Work Act 2009 (Cth). These standards regulate employment conditions and paid leave. Employees who are associated with the day-to-day operations of a local mine or mines and who are not located in head office or corporate administration offices are also covered by the Black Coal Mining Industry Award 2010 which regulates conditions including termination arrangements; pay and hours of work.

Unfair dismissal, enterprise bargaining, bullying claims, industrial actions and resolution of workplace disputes are also regulated under state and federal legislation. Some of the workers at Curragh are covered by the EA, which was approved by the Fair Work Commission, Australia’s national workplace relations tribunal. See “—Human Capital Disclosures” above.

Regulatory Matters—United States

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, protection of the environment, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant requirements mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. Because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. The summary below is a non-exhaustive summary of material legislation that applies to our U.S. Operations. Although this summary focuses on federal laws, most states (including Virginia, West Virginia and Pennsylvania) have their own regulatory schemes that either mirror federal laws or create additional layers of regulation.

Clean Air Act of 1970

The U.S. Clean Air Act of 1970, or the CAA, regulates airborne pollution that may be potentially detrimental to human health, the environment or natural resources. The CAA and comparable state laws that govern air emissions affect U.S. coal mining operations both directly and indirectly.

Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter, or PM, nitrogen dioxide, ozone and sulfur dioxide, or SO₂. For example, the U.S. Environmental Protection Agency, or the EPA, pursuant to the CAA, administers rules that apply PM emissions limits to emissions from coal preparation and processing plants constructed or modified after April 28, 2008. In addition, in recent years, the EPA has adopted more stringent national ambient air quality standards, or NAAQS for PM, nitrogen oxide, ozone and SO₂. It is possible that these modifications as well as future modifications to NAAQS could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, the EPA designating new areas of the country as being in nonattainment of applicable NAAQS or expanding existing nonattainment areas, and prompting additional local control measures pursuant to state implementation plans, or SIPs, required to address such revised NAAQS. SIPs may be state-specific or regional in scope. Under the CAA, individual states have up to 12 years from the date of designation of attainment/nonattainment areas to secure reductions from emission sources.

The CAA also indirectly, but significantly, affects the U.S. coal industry by extensively regulating the SO₂, nitrogen oxides, mercury, PM, greenhouse gases, and other substances emitted by coal-burning facilities, such as steel manufacturers, coke ovens and coal-fired electric power generating facilities. Over time, the EPA has promulgated or proposed CAA regulations to impose more stringent air emission standards for a number of these coal-burning industries, especially the power generation sector. While the EPA under the Trump Administration moved toward repealing or loosening some of those regulations, it is unclear the extent to which the Trump Administration’s deregulatory changes for coal-burning facilities under the CAA will survive under the Biden Administration. This is particularly the case for greenhouse gas emissions from coal-fired electric generating facilities, as President Biden has called for bringing the U.S. power sector to zero greenhouse gas emissions by 2035. Collectively, CAA regulations and uncertainty around future CAA requirements could reduce the demand

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for coal and, depending on the extent of such reduction, could have a material adverse effect on our business, financial condition and operations.

NAAQS Revisions. The CAA requires the EPA to periodically review and, if appropriate, revise the NAAQS to ensure protection of public health. In recent years, the EPA has reviewed the NAAQS for PM, ozone and SO₂. The PM NAAQS was last revised and made more stringent in 2012. Individual states have developed SIPs, which detail the PM emission reductions their sources must meet in order for the state to maintain or achieve the 2012 PM NAAQS. On April 14, 2020, the EPA announced its intention to retain, without changes, the 2012 PM NAAQS. This action was finalized by EPA on December 18, 2020. On June 10, 2021, EPA announced that it would reconsider this decision in light of scientific evidence pointing to health issues caused by exposure to PM. EPA expects to issue a proposed rule with more stringent standards for PM in Summer 2022 and a final rule in Spring 2023.

In 2015, the EPA issued a final rule reducing the primary ozone NAAQS from 75 to 70 parts per billion but retaining the existing secondary ozone NAAQS. States with moderate or high nonattainment areas must submit SIPs for the 2015 ozone NAAQS by October 2021. Environmental and industry groups challenged the 2015 ozone NAAQS in the U.S. Court of Appeals for the D.C. Circuit. On August 23, 2019, the court denied all the petitions for review against the 2015 primary NAAQS but concluded that the EPA had not provided a sufficient rationale for its decision on the 2015 secondary NAAQS and remanded that standard to the EPA. Prior to the court’s decision, EPA initiated another periodic review of the ozone NAAQS. This most recent review culminated in a final rule by the EPA on December 31, 2020 to retain all aspects of the 2015 ozone NAAQS, including the secondary standard with additional rationale in response to the court’s 2019 decision. It remains to be seen whether there will be legal challenges to the December 2020 final rule, or whether the EPA will reconsider the rule under the new administration. More stringent ozone or PM NAAQS, if promulgated, would require new SIPs to be developed and filed with the EPA and may trigger additional control technology for mining equipment or coal-burning facilities, or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation of any new requirements triggered by any future, more stringent NAAQS for nitrogen oxide and SO₂, although the EPA promulgated a final rule on March 18, 2019 that retains, without revision, the existing NAAQS for SO₂ of 75 parts per billion average over an hour.

Cross State Air Pollution Rule, or CSAPR. The CAA includes a so-called Good Neighbor Provision that requires upwind states to eliminate their significant contributions to downwind states’ nonattainment of the NAAQS. On July 6, 2011, the EPA finalized the CSAPR, which was meant to satisfy this Good Neighbor Provision. CSAPR requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in downwind states. Following litigation in the D.C. Circuit and U.S. Supreme Court, the first phase of the nitrogen oxide and SO2 emissions reductions required by CSAPR commenced in January 2015; further reductions of both pollutants in the second phase of CSAPR became effective in January 2017.

On October 26, 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 NAAQS for ground-level ozone. This rule imposed further reductions in nitrogen oxides emissions beginning in 2017 in 22 upwind states subject to CSAPR. According to the EPA, these reductions would reduce, but not eliminate, the upwind states’ significant contributions to downwind states’ air pollution. The CSAPR Update Rule did not include any deadline by which upwind states would have to completely eliminate their significant contributions to downwind states’ air pollution. The EPA maintained, however, that the rule would assist downwind states in bringing their areas of “moderate” nonattainment with the 2008 ozone NAAQS into compliance by the CAA-mandated July 20, 2018 deadline.

On December 6, 2018, the EPA followed up the CSAPR Update Rule with the CSAPR Close-Out. Pursuant to the CSAPR Close Out, the EPA found that it would not be feasible to impose cost-effective emissions on twenty upwind states before 2023, which was two years after the CAA-mandated 2021 deadline for states to bring their areas of “severe” nonattainment into compliance with the 2008 NAAQS. The EPA further concluded that the downwind states would achieve compliance with the 2008 NAAQS by 2023 even without further reductions by the upwind states, and the CSAPR Close-Out therefore required no further reductions from the upwind states beyond those required by the CSAPR Update Rule.

The CSAPR Update Rule and the CSAPR Close-Out were both challenged in the D.C. Circuit. On September 13, 2019, the D.C. Circuit found that upwind states had to eliminate any significant contributions to downwind states’ air pollution by the applicable 2008 NAAQS for ground-level ozone deadline, regardless of questions of

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feasibility. Pursuant to the D.C. Circuit’s ruling, the CSAPR Update Rule was remanded to the EPA. On October 1, 2019, the D.C. Circuit issued a judgment vacating the CSAPR Close-Out on the same basis.

On October 15, 2020, EPA proposed the Revised CSAPR Update Rule, which fully addressed twenty-one states’ outstanding interstate pollution transport obligations for the 2008 NAAQS for ozone. For nine states, EPA found that their projected 2021 emissions do not significantly contribute to non-attainment and/or maintenance problems in downwind states. The remaining twelve states were found to contribute to the non-attainment and/or maintenance problems in downwind states. EPA proposed to issue new or amended Federal Implementation Plans requiring additional emissions reductions from electricity generating units in those states beginning in the 2021 ozone season. On March 15, 2021, EPA finalized a rule update that requires additional emissions reduction of nitrogen oxides from power plants in twelve states. Additional emission reduction requirements in these states could adversely affect the demand for coal.

Mercury and Air Toxic Standards, or MATS. The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the New Source Performance Standards, or NSPS, for nitrogen oxides, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed Maximum Achievable Control Technology, or MACT, emission limits on hazardous air pollutants, or HAPs, from new and existing coal-fueled and oil-fueled electricity generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls. Although the MATS rule has been and continues to be the subject of EPA review and litigation, it remains in effect and has contributed to the need for many coal-fired power plants to install addition pollution controls, convert to natural gas, or retire

Following issuance of the final MATS rule, numerous petitions for review were filed. After proceedings before the U.S. Court of Appeals for the D.C. Circuit, the U.S. Supreme Court on June 29, 2015 held that EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from new and existing coal-fueled and oil-fueled power plants. The Supreme Court remanded the case to the D.C. Circuit, which ultimately allowed the rule to remain in effect while EPA promulgated a series of supplemental findings on the costs and benefits of the rule in response to the Supreme Court’s ruling.

Most recently, on May 22, 2020, the EPA finalized a supplemental finding, or Supplemental Cost Finding, that health and environmental benefits not directly related to mercury pollution should not be included in the benefit portion of the analysis. Using this framework EPA found that the costs of the MATS rule “grossly outweigh” any possible benefits and, therefore, that that regulating HAPs from coal-fired and oil-fired power plants is not “appropriate and necessary” under the CAA. However, EPA determined that while it could revise the cost-benefit analysis for the MATS rule, it could not remove coal-fired plants from HAPs regulation. The MATS rule therefore remains in effect. EPA also determined in the Supplemental Cost Finding that the MATS rule is adequately protective of public health, as required by the CAA’s residual risk and technology review provisions. Westmoreland Mining Holdings, a coal company, filed a petition with the D.C. Circuit in May 2020 challenging the legality of the MATS rule. Health and medical groups and other industry groups filed a petition of review opposing the Supplemental Cost Finding, and its reversal of the previous finding that it was “appropriate and necessary” to regulate HAPs. Environmental groups also challenge the EPA’s residual risk and technology review of the MATS rule, arguing that more stringent standards are necessary. This litigation remains ongoing. While the vast majority of coal-fired power producers have already complied with the 2012 MATS rule standards, any future reductions in the standards due to the ongoing litigation or additional EPA action could increase the cost of coal-fired electric power generation and negatively impact the demand for coal.

Clean Power Plan and Affordable Clean Energy, or ACE. In 2014, the EPA proposed a sweeping rule, known as the “Clean Power Plan,” to cut carbon emissions from existing electricity generating units, including coal-fired power plants. A final version of the Clean Power Plan was adopted in August 2015. The Clean Power Plan aimed to reduce carbon dioxide emissions from electrical power generation by 32% by 2030 relative to 2005 levels through the reduction of emissions from coal-burning power plants and increased use of renewable energy and energy conservation methods. Under the Clean Power Plan, states were free to reduce emissions by various means and were to submit emissions reduction plans to the EPA by September 2016 or, with an approved extension, September 2018. If a state had not submitted a plan by then, the Clean Power Plan authorized the EPA to impose its own plan on that state. In order to determine a state’s goal, the EPA divided the country into three regions based on connected regional electricity grids. States were to implement their plans by focusing on (i) increasing the generation efficiency of existing fossil fuel plants, (ii) substituting lower carbon dioxide emitting

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natural gas generation for coal-powered generation and (iii) substituting generation from new zero carbon dioxide emitting renewable sources for fossil fuel powered generation. States were permitted to use regionally available low carbon generation sources when substituting for in-state coal generation and to coordinate with other states to develop multi-state plans.

Following adoption, in 2015 twenty-seven states sued the EPA in the D.C. Circuit, claiming that the EPA overstepped its legal authority in adopting the Clean Power Plan. In February 2016, the U.S. Supreme Court ordered the EPA to halt enforcement of the Clean Power Plan until the lower court ruled on the lawsuit and until the Supreme Court determined whether or not to hear the case.

In a parallel litigation, twenty-five states and other parties filed lawsuits challenging the EPA’s final NSPS rules for carbon dioxide emissions from new, modified, and reconstructed power plants under the CAA. One of the primary issues in these lawsuits was the EPA’s establishment of standards of performance based on technologies including carbon capture and sequestration, or CCS. New coal plants could not meet the new standards unless they implement CCS. In conjunction with the EPA’s proposal to rescind the Clean Power Plan, the EPA also requested a stay of the NSPS litigation. The D.C. Circuit granted the request.

In October 2017, the EPA commenced rulemaking proceedings to rescind the Clean Power Plan, and in December 2017, the EPA published an Advanced Notice of Proposed Rulemaking announcing its intent to commence a new rulemaking to replace the Clean Power Plan with an alternative framework for regulating carbon dioxide. The rulemaking would culminate in the EPA replacing the Clean Power Plan with ACE. On September 17, 2019, the U.S. Court of Appeals for the D.C. Circuit dismissed the Clean Power Plan litigation and NSPS litigation as moot in light of the ACE rule.

On June 19, 2019, the EPA finalized the ACE rule as a replacement for the Clean Power Plan. The ACE rule establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE rule has several components: a determination of the best system of emission reduction for greenhouse gas emissions from coal-fired power plants, a list of “candidate technologies” states can use when developing their plans, and new implementing regulations for emission guidelines under Section 111(d) of the CAA. Unlike the Clean Power Plan, the ACE rule only includes as candidate technologies those that increase the efficiency of individual emission units, also referred to as heat rate improvement measures; the ACE rule does not include other methods such as co-firing with natural gas or adding renewable generation facilities.

Upon finalization of the ACE rule, the rule was subject to a challenge in the D.C. Circuit in American Lung Association et al. v. EPA, et al. On January 19, 2021, the D.C. Circuit vacated the ACE rule and remanded the question of the “best system of emission reduction” for carbon dioxide emissions from existing power plants to EPA for further consideration. In reaching its decision, the court found that ACE would not be the most effective means of reducing emissions, and further rejected the idea that EPA is limited under the Clean Air Act to only regulate emissions reductions at the source. On February 22, 2021, the D.C. Circuit Court granted EPA’s motion to stay issuance of the mandate to repeal until EPA could respond to the remand in a new rulemaking action.

In addition to potential CAA regulatory changes, it is possible that other future international, federal and state initiatives to control greenhouse gas emissions could increase costs associated with coal production and consumption, such as costs for additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Future regulation in the United States could occur pursuant to future treaty commitments, new domestic legislation or regulation by the EPA. On February 19, 2021, the United States rejoined the international climate agreement reached at the United Nations Framework Convention on Climate Change in Paris, France during December 2015, also known as the Paris Agreement. President Trump previously withdrew the United States from the Paris Agreement, beginning a four-year exit process. In an executive order, President Biden directed that federal agencies review recent actions that the President believes may interfere with the United States’ participation in the Paris Agreement. While the Paris Agreement sets only voluntary pledges for reducing greenhouse gas emissions, the recent executive actions signal a shift toward consideration of new or more stringent federal regulations to further reduce greenhouse gas emissions in the United States. In addition, many states, regions and governmental bodies have already adopted their own greenhouse gas emission reduction initiatives and have or are considering the imposition of fees or taxes based on the such emission by certain facilities, including coal-fired electric generating facilities. Others have announced their intent to increase the use of renewable energy sources, with the goal of displacing coal and other fossil fuels. Federal legislation along these lines is also a possibility. Depending on

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the particular regulatory programs or new laws enacted at the federal and state levels, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

There have also been numerous challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions under future laws. In addition, several permits issued to new coal-fueled power plants without greenhouse gas emission limits have been appealed to the EPA's Environmental Appeals Board. A federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. The United States Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions. The United States Supreme Court did not, however, decide whether similar claims can be brought under state common law. As a result, tort-type liabilities remain a concern. To the extent that these risks affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for coal.

Regional Haze. The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally national parks, national wilderness areas and international parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as SO2, nitrogen oxide and PM. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective”, the final guidance recommends comparing cost to visibility benefits. SIPs will be required by July 31, 2021. If states adopt SIPs with more stringent requirements, demand for coal could be affected.

New Source Review, or NSR. Pursuant to NSR regulations, stationary sources of air pollution must obtain an NSR permit prior to beginning construction of a new “major” source of emissions or a “major” modification of an existing major source. If a project is determined to trigger NSR, Prevention of Significant Deterioration regulations require the project to implement Best Available Control Technology and/or Non-Attainment New Source Review Lowest Achievable Emission Rate control technology.

Beginning in the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these NSR standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants.

The remaining litigation and uncertainty around the NSR program rules could impact demand for coal. In recent years, EPA proposed and promulgated several revisions to its NSR regulations and policies concerning NSR permitting. For example, one such change, known as the Project Emissions Accounting Rule on October 22, 2020, revises the NSR regulations to clarify that recent emission decreases can be considered in part of the NSR applicability test. In addition, the EPA on November 14, 2018 issued a final rule that clarified the appropriate test for determining whether two nominally separate modifications to existing facilities should be considered in a single NSR applicability analysis. While these changes have the potential to reduce NSR permitting burdens for coal-fired power plants and other coal-burning facilities, their fate under the Biden Administration remains uncertain.

Coke Ovens. Coke Oven Batteries and Coke Ovens: Pushing, Quenching, and Battery Stacks are two source categories regulated by the CAA. The initial technology-based standards for Coke Oven Batteries were promulgated by EPA in 1993. In 2003, EPA issued technology-based standards for Coke Ovens: Pushing, Quenching, and Battery Stacks. In 2005, EPA revised the technology-based standards and issued risk-based standards following a residual risk review. On June 26, 2020, the United States District Court for the Northern District of California found EPA had violated its statutory duty to perform a technology review of its initial

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technology-based standards for Coke Ovens: Pushing, Quenching, and Battery Stacks and a residual risk review of those standards. The court also found that EPA had violated its statutory duty to conduct a follow-up technology review and second residual risk review of the standards for Coke Oven Batteries. The court held that EPA has 30 months to comply with its statutory duty for these two source categories. To the extent that EPA ultimately promulgates more stringent technology-based standards as a result of the court-ordered technology and residual risk reviews, it could affect our current and prospective customers and may affect long-term demand for coal.

On January 21, 2021, President Biden issued an executive order that ordered the review of certain environmental regulations promulgated under the Trump administration. Those environmental regulations include ozone and particulate matter NAAQS, the ACE rule, and other air emission rules potentially affecting coal-fired power plants and other coal-burning facilities. It is unclear what affect this order will have on the demand for coal.

Clean Water Act of 1972

The U.S. Clean Water Act of 1972, or the CWA, and corresponding state law governs the discharge of toxic and non-toxic pollutants into the waters of the United States. CWA requirements may directly or indirectly affect U.S. coal mining operations.

Water Discharge. The CWA and corresponding state laws affect coal mining operations by imposing restrictions on discharges of wastewater into waters of the United States through the National Pollutant Discharge Elimination System, or NPDES, or an equally stringent program delegated to a state agency. The EPA and states may develop standards and limitations for certain pollutants, including through the technology-based standard program and water quality standard program. These restrictions often require us to pre-treat the wastewater prior to discharging it. NPDES permits require regular monitoring, reporting and compliance with effluent limitations. New requirements under the CWA and corresponding state laws may cause us to incur significant additional costs that could adversely affect our operating results.

Dredge and Fill Permits. Many mining activities, such as the development of refuse impoundments, fresh water impoundments, refuse fills, and other similar structures, may result in impacts to waters of the United States, including wetlands, streams and, in certain instances, man-made conveyances that have a hydrologic connection to such streams or wetlands. Under the CWA, coal companies are also required to obtain a Section 404 permit from the USACE prior to conducting certain mining activities, such as the development of refuse and slurry impoundments, fresh water impoundments, refuse fills and other similar structures that may affect waters of the United States, including wetlands, streams and, in certain instances, man-made conveyances that have a hydrologic connection to streams or wetlands. The USACE is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse effects on the environment. Permits issued pursuant to Nationwide Permit 21, or NWP 21, generally authorize the disposal of dredged and fill material from surface coal mining activities into waters of the United States, subject to certain restrictions. Since March 2007, permits under NWP 21 were reissued for a five-year period with new provisions intended to strengthen environmental protections. There must be appropriate mitigation in accordance with nationwide general permit conditions rather than less restricted state-required mitigation requirements, and permit holders must receive explicit authorization from the USACE before proceeding with proposed mining activities. The USACE may also issue individual permits for mining activities that do not qualify for Nationwide Permit 21.

The CWR/Navigable Waters Protection, or NWPR. Recent regulatory actions and court decisions have created some uncertainty over the scope of CWA jurisdiction. On June 29, 2015, the EPA and the USACE jointly promulgated final rules, collectively known as the Clean Water Rule, or the CWR, redefining the scope of waters protected under the CWA, revising regulations that had been in place for more than 25 years. These rules expanded the scope of CWA jurisdiction, making discharges into more bodies of water subject to the CWA’s permitting and other requirements. Following the CWR’s promulgation, numerous industry groups, states, and environmental groups challenged the CWR. On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the CWR’s implementation nationwide, pending further action in court. Further, on February 28, 2017, President Trump signed an executive order directing the relevant executive agencies to review the CWR, and on July 27, 2017, the EPA and the USACE published a proposed rule to rescind the CWR. On January 22, 2018, the Supreme Court reversed the Sixth Circuit’s decision, ruling that jurisdiction over challenges to the CWR rests with the federal district courts and not with the appellate courts, which was followed by the dissolution of the stay by the Sixth Circuit, and on February 6, 2018, in response to the January 2018 Supreme Court decision, the agencies published a final rule to postpone the adoption of CWR and maintain the status quo (the pre-2015 rule)

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through February 6, 2020 pending the agencies’ review of the CWR. Multiple states and environmental groups have filed challenges to this delay. On August 16, 2018, the federal court in South Carolina enjoined the February 6, 2018 rule, effectively reinstating the CWR in Virginia and Pennsylvania (where we have operations) and in 24 other states. The injunction is being challenged on appeal.

On April 21, 2020, the EPA and the USACE published the Navigable Waters Protection Rules, or the NWPR. The NWPR revises the definition of waters of the United States and replaces the CWR. The NWPR shrinks the agencies’ jurisdiction, particularly as it relates to tributaries and adjacent waters. The NWPR went into effect on June 22, 2020. The NWPR was enjoined in Colorado, but this decision was overturned by the Tenth Circuit Court of Appeals. On December 7, 2021, the EPA and the USACE announced a proposed rule to revise the definition of “waters of the United States.” The new definition would reflect the pre-2015 definition as well as consideration of recent Supreme Court decisions.

On April 22, 2020, in an unrelated case the Supreme Court ruled that provisions of the CWA require an NPDES permit when there is a direct discharge from a point source to navigable waters or the functionally equivalent discharge to groundwater. The NWPR, however, had excluded groundwater from the agencies’ jurisdiction. On January 21, 2021, EPA issued guidance applying the ruling of the Supreme Court to the NPDES permitting program. Under the Biden Administration, the EPA rescinded this guidance memorandum, thus eliminating a new factor that likely would have reduced clean water protections.

The Department of Justice has filed motions in various federal courts asking for remand of the NWPR back to the EPA and the USACE. Litigation of this matter remains ongoing. Uncertainty surrounding the NWPR remains, including what impact it may have on our operations.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful. The Court vacated those portions of the rule.

On August 31, 2020, the EPA finalized a rule to revise the guidelines and standards for the steam electric power generating point source category applicable to two categories of wastewater streams regulated by the 2015 rule: flue gas desulfurization wastewater, or FGD, and bottom ash transport water, or BA. With respect to FGD, selenium standards are less stringent than under the 2015 rule, and certain types of facilities, such as facilities with high FGD flow, low utilization boilers and those set to retire coal combustion units, are subject to less stringent effluent limits. The compliance deadline for FGD technology-based wastewater limits was extended from December 31, 2023 to December 31, 2025. With respect to BA, the EPA, among other things, eliminated a strict no-discharge requirement and implemented a not-to-exceed ten-percent volumetric purge. We cannot at this time predict how this rule will be enforced by the new Biden administration or if it will seek a revision.

The Biden Administration’s January 20, 2021 executive order for review of environmental regulations indicated the Biden Administration would review the NWPR amongst other CWA-related regulations.

Surface Mining Control and Reclamation Act of 1977

The Surface Mining Control and Reclamation Act of 1977, or the SMCRA, which is administered by the U.S. Office of Surface Mining Reclamation and Enforcement, or OSM, establishes operational, reclamation and closure standards for all aspects of surface mining and many aspects of underground mining in the United States. Unlike the CAA and the CWA, SMCRA is primarily concerned with the holistic regulation of coal mining as an industry. Its general environmental standards require surface operations to mine in such a way as to “maximize the utilization and conservation” of coal while using the best technology currently available to minimize land disturbance and adverse impacts on wildlife, fish, and environmental values. SMCRA requires operators to accomplish these goals by restoring the land to its approximate pre-mining condition and contour.

The SMCRA implements its environmental standards through “cooperative federalism.” Under the SMCRA, a state may submit a qualifying surface mining regulatory scheme to the OSM, and request to exert exclusive jurisdiction over surface mining activities within its territory. If OSM finds that the state’s scheme meets SMCRA’s

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requirements and gives approval, the state becomes the primary regulatory authority with oversight from OSM. If a state has a surface mining regulatory scheme that is less stringent than the surface mining standards under SMCRA and OSM regulations, or if mining on federal lands is involved, the OSM will impose federal regulations on surface mining in that state. Each of Virginia, West Virginia and Pennsylvania, where our Buchanan, Logan, Greenbrier and Mon Valley operations are based, has adopted qualifying surface mining regulatory schemes and has primary jurisdiction over surface mining activities within their respective territories. However, even if a state gains approval for its surface mining regulatory program, the OSM retains significant federal oversight, including the ability to perform inspections of all surface mining sites to ensure state program and mine operator compliance with federal minimum standards. The OSM and its state counterparts also oversee and evaluate standards of:

•performance (both during operations and during reclamation);

•permitting (applications must describe the pre-mining environmental conditions and land use, the intended mining and reclamation standards, and the post-mining use);

•financial assurance (SMCRA requires that mining companies post a bond sufficient to cover the cost of reclaiming the site, and the bond is not released until mining is complete, the land has been reclaimed and the OSM has approved the release);

•inspection and enforcement (including the issuance of notices of violation and the placement of a mining operation, its owners and controllers on a federal database known as the Applicant Violator System, meaning that such person or entity is blocked from obtaining future mining permits); and

•land restrictions (SMCRA prohibits surface mining on certain lands and also allows citizens to challenge surface mining operations on the grounds that they will cause a negative environmental impact).

Regulations under the SMCRA and its state analogues provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls us or is under common ownership or control with us have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension.

Under the SMCRA and its state law counterparts, all coal mining applications must include mandatory “ownership and control” information, which generally includes listing the names of the operator’s officers and directors, and its principal stockholders owning 10% or more of its voting shares, among others. Ownership and control reporting requirements are designed to allow regulatory review of any entities or persons deemed to have ownership or control of a coal mine, and bar the granting of a coal mining permit to any such entity or person (including any “owner and controller”) who has had a mining permit revoked or suspended, or a bond or similar security forfeited within the five-year period preceding a permit application or application for a permit revision. Similarly, regulatory agencies also block the issuance of permits to applicants, their owners or their controlling persons, who have outstanding permit violations that have not been timely abated.

These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including among others, the following:

•being an officer or director of an entity;

•being the operator of the coal mining operation;

•having the ability to commit the financial or real property assets or working resources of the permittee or operator; and

•owning of record 10% or more of the mining operator.

This presumption, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which the relevant coal mining operation is conducted.

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We must file an ownership and control notice each time an entity obtains a 10% or greater interest in us. If we or entities or persons deemed to have ownership of control of us have unabated violations of SMCRA or its state law counterparts, have a coal mining permit suspended or revoked, or forfeit a reclamation bond, we and our owners and controllers may be prohibited from obtaining new coal mining permits, or amendments to existing permits, until such violations or other matters are corrected. This is known as being “permit-blocked.” Additionally, if an owner or controller of us is deemed an owner or controller of other mining companies, we could be permit-blocked based upon the violations of, or permit-blocked status of, an owner or controller of such other mining companies. If our owner or controller were to become permit blocked, this could adversely affect production from our properties.

In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive activism and litigation by environmental groups. After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Monetary sanctions and, in certain circumstances, even criminal sanctions may be imposed for failure to comply with the SMCRA permits. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation bonding requirements.

SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority. For our U.S. Operations, we meet our reclamation bonding requirements by posting surety bonds and participation in the Commonwealth of Virginia bond pool. Our total amount of reclamation surety bonds outstanding was approximately $28.5 million as of December 31, 2021. The surety bond requirements for a mine represent the calculated cost to reclaim the current operations if it ceased to operate in the current period. The cost calculation for each surety bond must be completed according to the regulatory authority of each state.

The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the United States. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically based on changes in federal legislation. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2012 through September 30, 2021, the fee is $0.31 and $0.13 per Mt of surface-mined and underground-mined coal, respectively. See Item 2. “Properties” for information regarding reclamation and other taxes applicable to our U.S. mining properties.

While SMCRA is a comprehensive statute, SMCRA does not supersede the need for compliance with other major environmental statutes, including the Endangered Species Act of 1973, or the ESA, CAA, CWA, the Resource Conservation and Recovery Act of 1976, or the RCRA, and the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA.

National Environmental Policy Act of 1969

The National Environmental Policy Act of 1969, or NEPA, applies to mining operations or permitting requirements that require federal approvals, NEPA requires federal agencies to evaluate the environmental impact of all “major federal actions” significantly affecting the quality of the human environment. NEPA requires federal agencies, such as the EPA or the OSM, to incorporate environmental considerations in their planning and decision-making. The federal agency carrying out the requirements of NEPA must prepare a detailed statement assessing the environmental impact of and alternatives to the particular action requiring agency approval. These statements are referred to as Environmental Impact Statements or Environmental Assessments. NEPA also defines the processes for evaluating and communicating environmental consequences of federal decisions and actions, such as the permitting of new mine development on federal lands. U.S. coal mining companies must provide information to agencies with respect to proposed actions that will be under the authority of the federal

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government. The NEPA process involves public participation and can involve lengthy timeframes. Ultimately, federal agencies may require mitigation measures pursuant to their NEPA review.

On July 16, 2020, the White House Council on Environmental Quality, or the CEQ finalized a proposed rule, which went into effect on September 14, 2020. The new rule made it easier to obtain approval for new projects, including by eliminating the need to evaluate so-called cumulative impacts which could ultimately limit agencies’ consideration of climate change and greenhouse gas emissions. However, pursuant to Executive Order 13990, CEQ began a comprehensive review of the 2020 rule and announced a phased approach to amending NEPA regulations. An Interim Final Rule was issued June 29, 2021 which extended the deadline for Federal agencies to develop or update their NEPA implementing procedures to conform to the CEQ regulations by two years.

Solid Waste Disposal Act of 1995 and Resource Conservation and Recovery Act of 1976

The Solid Waste Disposal Act of 1965, or SWDA, was the first federal act to target waste disposal technology. The SWDA governs disposal of both municipal and industrial waste, promotes advancement of waste management technology and sets waste management standards. The SWDA was amended by the Resource Conservation and Recovery Act of 1976, or RCRA. RCRA affects U.S. coal mining operations by establishing “cradle to grave” requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. The RCRA also addresses the environmental effects of certain past hazardous waste treatment, storage and disposal practices, and may require a current or past site owner or operator to remove improperly disposed hazardous wastes. The RCRA also sets forth a framework for managing certain non-hazardous solid wastes. Part or all of the RCRA program may be delegated to a state pursuant to a state implementation plan if the state standards are at least as stringent as federal standards.

Subtitle C of the RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on disposal of coal combustion residuals, or CCR or coal ash, by electric utilities and independent power producers. As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. On August 24, 2018, the U.S. Court of Appeals for the D.C. Circuit held that certain provisions of the EPA’s CCR rule were not sufficiently protective, and it invalidated those provisions. Since then, the EPA has finalized changes to its CCR regulations in response to some aspects of the court’s ruling, primarily to regulate unlined ponds but extend certain deadlines for initiating their closure, and allowing site-specific alternate liner determinations.

The Biden Administration’s January 20, 2021 executive order for review of environmental regulations indicated that the Biden Administration will review environmental regulations affecting the management and disposal of CCR. On January 11, 2022, the EPA announced that it was taking steps to protect groundwater from coal ash contamination, including plans to finalize a federal permitting program for the disposal of coal ash and establishing regulations for legacy coal ash surface impoundments. We cannot predict at this time if and/or when such rules will go into effect.

The EPA regulations on CCR management and disposal exempt coal ash that is disposed of at mine sites and reserve any regulation thereof to the Office of Surface Mining Reclamation and Enforcement or "OSMRE." After proposing CCR regulations in 2007, the OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. In addition, while many mining wastes such as overburden and coal cleaning wastes are exempt from RCRA hazardous waste regulations, certain wastes may be subject to the RCRA’s requirements. The RCRA also governs underground storage tanks containing hazardous substances and petroleum products, which are used in some coal mining operations, although we do not have underground storage tanks associated with our U.S. Operations.

The Biden Administration’s January 20, 2021 executive order for review of environmental regulations indicated that the Biden Administration will review environmental regulations affecting the management and disposal of CCR. It is unclear what effect this order will have on the demand for coal.

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Comprehensive Environmental Response, Compensation, and Liability Act of 1980

Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, authorizes the federal government and private parties to recover costs to address threatened or actual releases of hazardous substances (broadly defined) that may endanger public health or the environment. Current owners and operators of contaminated sites, past owners and operators of contaminated sites at the time hazardous substances were disposed, parties that arranged for the disposal or transport of the hazardous substances and transporters of hazardous substances could be potentially responsible parties, or PRPs, under CERCLA. PRPs may be liable for costs related to contaminated sites, including, but not limited to, site investigation and cleanup costs incurred by the government or other parties, damages to natural resources and costs of certain health assessments or studies. In addition, CERCLA authorizes the federal government to order PRPs to conduct investigation and cleanup of releases of hazardous substances at certain contaminated sites.

CERCLA requires that a list of contaminated sites, referred to as the National Priorities List, be compiled by EPA using certain criteria to evaluate the potential relative risk to the public health and the environment from releases or threatened releases of hazardous substances. Strict, joint and several and retroactive liability may be imposed on hazardous substance generators and facility owners and operators, regardless of fault or the legality of the original disposal activity. The failure to comply with a federal government order under CERCLA may result in civil penalties, including fines and/or punitive damages, in addition to the costs incurred by the federal government due to the party’s failure to comply with an order.

We could face liability under CERCLA and similar state laws for properties that (1) we currently own, lease or operate, (2) we, our predecessors, or former subsidiaries have previously owned, leased or operated, (3) sites to which we, our predecessors or former subsidiaries, sent waste materials, and (4) sites at which hazardous substances from our facilities’ operations have otherwise come to be located.

Federal Mine Safety and Health Act of 1977

The Mine Act, which was amended by the Mine Improvement and New Emergency Response Act of 2006, or the MINER Act, governs federal oversight of mine safety and authorizes the U.S. Department of Labor’s Mine Safety and Health Administration, or MSHA, to regulate safety and health conditions for employees working in mines within the United States, and to enforce various mandatory health and safety requirements. The Mine Act mandates four annual inspections of underground coal mines, two annual inspections of all surface coal mines, and permits inspections in response to employee complaints of unsafe working conditions. The statute and its regulations also mandate miner training, mine rescue teams for all underground mines, and involvement of miners and their representatives in health and safety activities. MSHA has also promulgated regulations governing a wide range of activities, including roof support, ventilation, combustible materials, electrical equipment, fire protection, explosives and blasting, and mine emergencies. MSHA has the statutory authority to issue civil penalties for non-compliance, to set the period for abatement of violations, and to seek injunctive relief requiring a company to cease operations until certain conditions are corrected. The MINER Act requires mine specific emergency response plans in underground coal mines, implemented new regulations regarding mine rescue teams and sealing of abandoned areas, requires prompt notification of mine accidents, and imposes enhanced civil and criminal penalties for violations. Various states also have enacted their own new laws and regulations addressing many of these same subjects. MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. For example, the second phase of MSHA’s respirable coal mine dust rule went into effect in February 2016 and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air. In the last several years, MSHA has also proposed regulations governing respirable silica, and the exposure of miners to underground diesel exhaust fumes, and testing, evaluation, and approval of electric motor-driven mine equipment and accessories. MSHA has issued guidance for employers and workers regarding how to mitigate the risks of COVID-19 rather than mandatory standards. During a September 29, 2021 stakeholder call, MSHA leadership indicated that it would not issue an Emergency Temporary Standard requiring COVID-19 vaccinations or testing at mine sites.

Black Lung (Coal Worker’s Pneumoconiosis)

The Mine Act amended the Federal Coal Mine Health and Safety Act of 1969, which is the legislation that mandates compensation for miners who were totally and permanently disabled by the progressive respiratory

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disease caused by coal workers’ pneumoconiosis, or black lung. Under current federal law, a U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current employees, and to claimants who are former employees who last worked for the operator after July 1, 1973, and whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on sales of U.S. production, excluding export sales, of up to $1.21 per Mt for deep-mined coal and up to $0.61 per Mt for surface-mined coal, each limited to 4.4% of the gross sales price. In 2019, these tax rates were cut in half compared to the pre-2019 level, falling to $0.61 per Mt of underground-mined coal or $0.31 per Mt of surface-mined coal, limited to 2% of the sales price. Our total excise taxes paid to this trust fund in 2020 were $0.9 million. In December 2019, President Trump signed into law a provision that restored the rate to its pre-2019 level through December 31, 2020. On December 27, 2020, then-President Trump extended the trust fund excise tax through December 31, 2021 at the pre-2019 rate. Historically, very few of the miners who sought federal black lung benefits were awarded these benefits; however, the approval rate has increased following implementation of black lung provisions contained in the Patient Protection and Affordable Care Act of 2010, or the Affordable Care Act. The Affordable Care Act introduced significant changes to the federal black lung program, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, and established a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. In addition to possibly incurring liability under federal statutes, we may also be liable under state laws for black lung claims. See Note 20 to the accompanying audited consolidated financial statements for further information of applicable insurance coverage.

National Labor Relations Act of 1935

The National Labor Relations Act of 1935, or the NLRA, governs collective bargaining and private sector labor and management relations. While we do not have a unionized workforce in the United States, to the extent that non-supervisory employees decide to seek representation or engage in other protected concerted labor activities, the NLRA and the rules promulgated by the National Labor Relations Board, or NLRB, set the parameters for employees’ and union activity and our response. The NLRA applies to both unionized and non-union workforces. Any employee complaints related to the pandemic and any related labor actions, if they are tied to terms and conditions of employment that affect the workforce generally, will be governed by the NLRA. In addition, recent NLRB- promulgated rules regarding joint employer status under the NLRA clarified the basis upon which contractors and vendors, as well as their employees (and the unions representing them), could allege that we are jointly and severally liable for any unfair labor practices or bargaining obligations of the third-party employer. While the rules made the joint employer test generally more employer-friendly, there is always the possibility of claims that we are a joint employer with a contractor or vendor.

Patient Protection and Affordable Care Act of 2010

The United States Patient Protection and Affordable Care Act, or the Affordable Care Act, was enacted in March 2010 and included substantial reforms to the U.S. health care system intended to increase affordability of health insurance, expand the Medicaid program and support innovative health care delivery methods designed to lower costs. The Affordable Care Act included a number of provisions designed to reduce Medicare expenditures and the cost of health care generally, to reduce fraud and abuse, and to provide access to increased health coverage. For example, the law prohibits insurers from refusing to cover preexisting conditions, requires coverage for certain types of care, and can subject certain large employers to a shared responsibility payment if they do not offer health coverage to their full-time employees. The Affordable Care Act also created government-run, taxpayer-funded health insurance marketplaces (known as “Exchanges”).

The Affordable Care Act impacts the coal mining industry’s costs of providing health care benefits to its eligible active employees, with both short term and long term implications. It affects health care costs by, among other things, setting the maximum age for covered dependents to receive benefits at 26, requiring certain benefits for occupational disease related illnesses, and eliminating lifetime dollar limits on essential benefits per covered individual and restrictions on annual dollar limits on essential benefits per covered individual. The Affordable Care Act also included significant changes to the federal black lung program, including an automatic survivor benefit paid upon death of a miner with an awarded black lung claim and the establishment of a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. The Affordable Care Act also provides lifetime benefits to certain dependents

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who survive the death of a miner, if the miner had been receiving the benefits before death. For additional information, please see above “––Black Lung (Coal Worker’s Pneumoconiosis).”

The Affordable Care Act has faced ongoing legal challenges, including litigation and legislation seeking to invalidate or modify some or all of the law or the manner in which it has been implemented. For example, the Further Consolidated Appropriations Act of 2020 repealed the “Cadillac tax,” which would have imposed a 40% tax on high-cost employer plans starting in 2022. The constitutionality of the individual mandate, and the entire Affordable Care Act, was challenged in the Fifth Circuit Court of Appeals, and is currently under review by the Supreme Court. The outcome of these cases is uncertain, and any change they make to the Affordable Care Act could have a significant impact on the U.S. health care industry and employers providing health coverage to their workers. Further, the fact that implementation of certain aspects of the Affordable Care Act can be affected by Executive Orders and regulations promulgated by federal governmental agencies that may change when a new President takes office also contributes to the uncertainty as to how the law will affect the U.S. health care industry and employers providing health coverage to their workers.

Safe Drinking Water Act of 1974

The Safe Drinking Water Act of 1974, or SDWA, is the federal law that protects public drinking water supplies throughout the United States. Under the SDWA, the EPA sets federal health-based standards for drinking water quality and implements technical and financial programs to ensure drinking water safety. The SDWA requires regular monitoring and reporting of water quality. The SDWA is applicable to public water systems that have at least 15 service connections or serve at least 25 people per day for 60 days of the year. Further, SDWA standards apply to water systems based on their type and size. There are four categories: i) community water systems, ii) non-community water systems, iii) non-transient, non-community water systems and iv) transient non-community water systems.

The SDWA requires the EPA to establish National Primary Drinking Water Regulations for contaminants that may cause adverse public health effects. These regulations include mandatory requirements and non-enforceable health goals. The EPA sets regulations for drinking water system concentrations of certain organic contaminants, inorganic contaminants, microbiological contaminants, disinfection byproducts, residual disinfectant levels, and radionuclide levels. The EPA also sets filtration requirements for drinking water systems that vary depending on the size of the population served by the system.

The SDWA also regulates the underground injection of fluids into porous formations or rocks through wells and similar conveyance systems, and regulates the construction, operation, permitting and closure of such wells.

The SDWA can impact coal mining operations in the United States to the extent that the operations could impact drinking water supplies.

National Historic Preservation Act of 1966

The National Historic Preservation Act of 1966, or NHPA, governs the preservation of historical properties throughout the United States. The NHPA requires the Department of the Interior’s National Park Service to implement the national policy to preserve for public use historic sites, buildings and objects of national significance for the inspiration and benefit of the people of the United States. Alternatively, a state may carry out this program with oversight from the Department of the Interior if the Department of the Interior approves the state’s historic preservation program. In executing this policy, the National Park Service identifies National Historic Landmarks and places them on a National Register of Historic Places. The NHPA requires that each federal agency prior to authorizing expenditure of federal funds on a federal or federally assisted undertaking, or prior to issuing a federal license for such an undertaking, consider the effect of the undertaking on historic resources and to provide the Advisory Council on Historic Preservation with a reasonable opportunity to comment on the undertaking. Accordingly, the NHPA could create an additional level of scrutiny on a coal mining operation, particularly during the permitting process, to the extent that a mining operation could come within the scope of a historical site. The SMCRA also provides protection for historic resources that would be adversely affected by mining operations by requiring the OSM to comply with the NHPA. If a property is listed on the National Register of Historic Places, SMCRA requires consideration of the property’s historic values in determining issuance of a surface coal mining permit.

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Endangered Species Act of 1973

The Endangered Species Act of 1973, or ESA, governs the protection of endangered species in the United States and requires the U.S. Department of the Interior’s Fish and Wildlife Service and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service to formally review any federally authorized, funded or administered action that could negatively affect endangered or threatened species. Under the ESA, the responsibilities of these agencies include listing and delisting species, designating critical habitats, developing recovery plans and conducting five-year reviews of listed species.

The Fish and Wildlife Service studies projects for possible effects to endangered species and then can recommend alternatives or mitigation measures. The OSM and state regulators require mining companies to hire a government-approved contractor to conduct surveys for potential endangered species, and the surveys require approval from state and federal biologists who provide guidance on how to minimize mines’ potential effects on endangered species. Certain endangered species are more typically at issue under the ESA with respect to mining, including the long-eared bat and Guyandotte crayfish, which are found in the Central Appalachian region, including parts of Virginia and West Virginia. Mitigation methods can cause increased costs to coal mining operators. Changes in listings or requirements under these regulations could have a material adverse effect on our costs or our ability to mine some of our properties in accordance with our current mining plans. The ESA allows landowners to receive a special permit to take listed species in some circumstances, provided they have developed a Habitat Conservation Plan approved by the Fish and Wildlife Service.

The U.S. Department of the Interior issued three proposed rules in July 2018 aiming to streamline and update the ESA, and they became effective on September 26, 2019. The rules weaken the protections afforded species listed as threatened, and make it more difficult to add species to the threatened and endangered species lists and easier to delist species. However, on June 4, 2021, the Fish and Wildlife Service and the National Oceanic and Atmospheric Administration's National Marine Fisheries Service announced a plan to strengthen the ESA and revise or rescind regulations passed under the Trump Administration.

Migratory Bird Treaty Act of 1918

The Migratory Bird Treaty Act of 1918, or MBTA, as modified by the Migratory Bird Treaty Reform Act of 2004, makes it unlawful without a waiver to pursue, hunt, take, capture, kill or sell migratory birds, or any part, nest or egg of any migratory bird. A migratory bird species is included on the list of species protected by the MBTA if it meets one or more of the following criteria: i) it occurs in the United States or U.S. territories as the result of natural biological or ecological processes and is currently, or was previously listed as, a species or part of a family protected by certain international treaties, or their amendments, entered into by the United States and Canada, Mexico, Japan or Russia; ii) revised taxonomy results in it being split from a species that was previously on the list, and the new species occurs in the United States or U.S. territories as the result of natural biological or ecological processes; or iii) new evidence exists for its natural occurrence in the United States or U.S. territories resulting from natural distributional changes and the species occurs in a protected family. The Migratory Bird Treaty Reform Act of 2004 requires the Fish and Wildlife Service to publish an informational list of all nonnative, human-introduced bird species to which MBTA does not apply. The most recent list of all nonnative, human-introduced bird species was published on April 16, 2020.

Since coal mining is seen as an industry that can threaten bird populations, coal operators are required to ensure that their operations do not negatively impact migratory birds, or to take mitigation measures. Violations of the MBTA are either misdemeanor or felonies punishable by a fine or imprisonment. Efforts in 2020 and 2021 to narrow the applicability of the MBTA were unsuccessful.

Regulation of explosives

Our surface mining operations are subject to numerous regulations relating to blasting activities, including the Federal Safe Explosives Act, or SEA. SEA applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials. Pursuant to federal regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest, including ammonium nitrate at certain threshold levels, must complete a screening review

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in order to help determine whether there is a high level of security risk such that a security vulnerability assessment and site security plan will be required. The Bureau of Alcohol, Tobacco and Firearms and Explosives, or ATF, regulates the sale, possession, storage and transportation of explosives in interstate commerce. In addition to ATF regulation, the U.S. Department of Homeland Security is evaluating a proposed ammonium nitrate security program rule. In 2015, the OSM also proposed a rulemaking addressing nitrogen oxide clouds from blasting; on July 30, 2019, however, the OSM withdrew the proposed rulemaking.

Available Information

We file annual, quarterly and current reports and other documents with the SEC under the Exchange Act. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any 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 filing such materials with, or furnishing such materials to, the SEC, on or through our internet website, https://coronadoglobal.com.au/. We are not including the information contained on, or accessible through, any website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K, unless expressly noted.

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ITEM 1A. RISK FACTORS.

An investment in our securities is speculative and involves a number of risks. We believe the risks described below are the material risks that we face. However, the risks described below may not be the only risks that we face. Additional unknown risks or risks that we currently consider immaterial, may also impair our business operations. You should carefully consider the specific risk factors discussed below, together with the information contained in this Annual Report on Form 10-K, including Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer, and the trading price of our securities could decline significantly.

Some of these risks include:

•Our business, financial condition and results of operations have been, and will continue to be, adversely affected by the ongoing COVID-19 pandemic;

•Our profitability depends upon the prices we receive for our coal. Prices for coal are volatile and can fluctuate widely based upon a number of factors beyond our control;

•We face increasing competition, which could adversely affect profitability;

•Demand for our Met coal is significantly dependent on the steel industry;

•We may face restricted access to international markets in the future;

•If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer;

•Take-or-pay arrangements within the coal industry could unfavorably affect our profitability;

•A decrease in the availability or increase in costs of key supplies, capital equipment, commodities and purchased components, such as diesel fuel, steel, explosives and tires could materially and adversely affect our financial condition and results of operations;

•Defects in title or loss of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs;

•A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity;

•Decreases in demand for coal-fired electricity and changes in thermal coal consumption patterns of the United States and Australian electric power generators could adversely affect our business;

•The existence (or claimed existence) of native title on land within our Australian tenements may impose restrictions on the construction of our expansion activities and our continued operations;

•Risks inherent to mining operations could impact the amount of coal produced, cause delay or suspend coal deliveries, or increase the cost of operating our business;

•Our long-term success depends upon our ability to continue discovering, or acquiring and developing assets containing, coal reserves that are economically recoverable;

•We rely on estimates of our recoverable resources and reserves, which are complex due to geological characteristics of the properties and the number of assumptions made;

•Our profitability could be affected adversely by the failure of suppliers and/or outside contractors to perform;

•Our inability to replace or repair damaged or destroyed equipment or facilities in a timely manner could materially and adversely affect our financial condition and results of operations;

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•Our ability to operate effectively could be impaired if we lose key personnel or fail to attract qualified personnel;

•We may be unable to obtain, renew or maintain permits necessary for our operations, which would reduce coal production, cash flows and profitability;

•In times of drought and/or shortage of available water, our operations and production, particularly at Curragh, could be negatively impacted if the regulators impose restrictions on our water offtake licenses that are required for water used in the CPPs;

•We may not have adequate insurance coverage for some business risks;

•Cybersecurity attacks, natural disasters, terrorist attacks and other similar crises or disruptions may negatively affect our business, financial condition and results of operations;

•Mining in the CAPP is more complex and involves more regulatory constraints than mining in other areas of the U.S., which could affect our mining operations and cost structures in these areas;

•The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues;

•If a substantial number of our customers fail to perform under our contracts with them, our revenues and operating profits could suffer;

•If our ability to collect payments from customers is impaired, our revenues and operating profits could suffer;

•Changes in credit ratings issued by nationally recognized statistical rating organizations could adversely affect our cost of financing and the market price of our securities;

•Our existing and future indebtedness may limit cash flow available to invest in the ongoing needs of our businesses, which could prevent us from fulfilling our obligations under our senior secured notes, senior secured asset-based revolving credit agreement in an initial aggregate principal amount of $100.0 million, or the ABL Facility, and other debt, and we may be forced to take other actions to satisfy our obligations under our debt, which may not be successful;

•We adjust our capital structure from time to time and may need to increase our debt leverage, which would make us more sensitive to the effects of economic downturns;

•Our business may require substantial ongoing capital expenditures, and we may not have access to the capital required to reach full productive capacity at our mines;

•We may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets;

•Risks related to our investment in WICET may adversely affect our financial condition and results of operations;

•Risks related to the Supply Deed with Stanwell may adversely affect our financial condition and results of operations;

•We could be adversely affected if we fail to appropriately provide financial assurances for our obligations;

•Mine closures entail substantial costs. If we prematurely close one or more of our mines, our operations and financial performance would likely be affected adversely;

•If the assumptions underlying our provision for reclamation and mine closure obligations prove to be inaccurate, we could be required to expend greater amounts than anticipated;

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•We are subject to foreign exchange risks involving certain operations in multiple countries;

•Interest rates could change substantially and have an adverse effect on our profitability;

•We may be unsuccessful in integrating the operations of acquisitions with our existing operations and in realizing all or any part of the anticipated benefits of any such acquisitions;

•Coronado Global Resources Inc. is a holding company with no operations of its own and, as such, it depends on its subsidiaries for cash to fund its operations and expenses, including future dividend payments, if any;

•We are subject to extensive health and safety laws and regulations that could have a material adverse effect on our reputation and financial condition and results of operations;

•We could be negatively affected if we fail to maintain satisfactory labor relations;

•Our operations may impact the environment or cause exposure to hazardous substances, which could result in material liabilities to us;

•Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion and coal mining in many jurisdictions, which could significantly affect demand for our products or our securities;

•Changes in and compliance with government policy, regulation or legislation may adversely affect our financial condition and results of operations;

•Failure to comply with applicable anti-corruption and trade laws, regulations and policies could result in fines and criminal penalties, causing a material adverse effect on our business, operating and financial prospects or performance;

•We are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively;

•We may be subject to litigation, the disposition of which could negatively affect our profitability and cash flow in a particular period, or have a material adverse effect on our business, financial condition and results of operations; and

•We have no registered trademarks for our Company name or other marks used by us in the United States or any other countries, and failure to obtain those registrations could adversely affect our business.

Economic, Competitive and Industry Risks

Our business, financial condition and results of operations have been, and will continue to be, adversely affected by the ongoing COVID-19 pandemic.

The ongoing COVID-19 pandemic has had a significant impact on the global economy and the ability of businesses to operate. Our business has been and may continue to be adversely affected by the global outbreak of COVID-19 and the impact could be material. Despite the availability of vaccines in some geographies, COVID-19 continues to spread in the countries in which we operate and our customers and suppliers are located, and uncertainties exist as to the efficacy of vaccines against new variants or mutations of COVID-19. In the attempt to mitigate or contain the spread of the virus, international, federal, state and local public health and governmental authorities have introduced measures and recommendations such as orders restricting movement and public gatherings and the implementation of social distancing protocols, orders for residents to stay at home with a limited range of exceptions, orders restricting travelling overseas or across borders (including interstate), and orders for all non-essential businesses to close, including certain mine sites unless their work is deemed critical, factories and office shutdowns. These restrictions have caused disruptions to mining operations (including Coronado’s operations), manufacturing operations and supply chains around the world.

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Although there has been an easing of restriction in certain jurisdictions, some of these restrictions have been reinstated in others, or could be reinstated in the near future, in the attempt to contain a resurgence or new COVID-19 outbreaks due to new variants or mutations of the virus.

The continued global spread of the COVID-19 pandemic and the responses thereto are complex and rapidly evolving, and the extent to which the pandemic impacts our business and results of operations, including the duration and magnitude of such impacts, will depend on numerous factors that we may not be able to accurately predict. COVID-19, and the volatile global economic conditions resulted from the pandemic, as well as reactions to future pandemics or resurgences of COVID-19, could also heighten other risks described in this “Item 1A. Risk Factors” section, which could have a material adverse impact in our business and results of operations. Additionally, there may be other adverse impacts to our business and results of operations from the spread of COVID-19 that we have not considered at this time. Therefore, we cannot assure that if COVID-19 continues to spread, it would not have a further adverse impact on our business and results of operations.

Our profitability depends upon the prices we receive for our coal. Prices for coal are volatile and can fluctuate widely based upon a number of factors beyond our control.

We generate revenue from the sale of coal and our financial results are materially impacted by the prices we receive. Prices and quantities under Met coal sales contracts in North America are generally based on expectations of the next year’s coal prices at the time the contract is entered into, renewed, extended or re-opened. Pricing in the global seaborne market is typically set on a rolling quarterly average benchmark price.

Sales by our U.S. Operations to the export market are typically priced with reference to a benchmark index. Sales by our Australian Operations have typically been contracted on an annual basis and are priced with reference to benchmark indices or bilaterally negotiated term prices and spot indices. As a result, a significant portion of our revenue is exposed to movements in coal prices and any weakening in Met or thermal coal prices would have an adverse impact on our financial condition and results of operations.

The expectation of future prices for coal depends upon many factors beyond our control, including the following:

•the current market price of coal;

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

•the consumption pattern of industrial consumers, electricity generators and residential users;

•weather conditions in our markets that affect the ability to produce Met coal or affect the demand for thermal coal;

•competition from other coal suppliers;

•technological advances affecting the steel production process and/or energy consumption;

•the costs, availability and capacity of transportation infrastructure; and

•the impact of domestic and foreign governmental policy, laws and regulations, including the imposition of tariffs, environmental and climate change regulations and other regulations affecting the coal mining industry, including regulations and measures introduced in response to the COVID-19 pandemic.

Met coal has been a volatile commodity over the past ten years. Recently, in the third quarter of 2021, seaborne prices reached record levels with both the Australian and U.S. Met coal price indices exceeding $400.0 per Mt, largely as result of continued strong global steel demand and tight supply. The demand and supply in the Met coal industry changes from time to time. There are no assurances that oversupply will not occur, that demand will not decrease or that overcapacity will not occur, which could cause declines in the prices of coal, which could have a material adverse effect on our financial condition and results of operations.

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In addition, coal prices are highly dependent on the outlook for coal consumption in large Asian economies, such as China, India, South Korea and Japan, as well as any changes in government policy regarding coal or energy in those countries. Seaborne Met coal import demand can also be significantly impacted by the availability of local coal production, particularly in the leading Met coal import countries of China and India, among others, and the competitiveness of seaborne Met coal supply, including from the leading Met coal exporting countries of Australia, the United States, Russia, Canada and Mongolia, among others.

We face increasing competition, which could adversely affect profitability.

Competition in the coal industry is based on many factors, including, among others, world supply, price, production capacity, coal quality and characteristics, transportation capability and costs, blending capability, brand name and diversified operations. We are subject to competition from Met coal producers from Australia, the United States, Russia, Canada, Mongolia and other Met coal producing countries. Should those competitors obtain a competitive advantage in comparison to us (whether by way of an increase in production capacity, higher realized prices, lower operating costs, export/import tariffs, being comparatively less impacted as a result of COVID-19 or otherwise), such competitive advantage may have an adverse impact on our ability to sell, or the prices at which we are able to sell coal products. In addition, some of our competitors may have more production capacity as well as greater financial, marketing, distribution and other resources than we do and may be subject to less stringent environmental and other regulations than we are.

The consolidation of the global Met coal industry in recent years has contributed to increased competition, and our competitive position may be adversely impacted by further consolidation among market participants or by further competitors entering into and exiting bankruptcy proceedings under a lower cost structure. Similarly, 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 and Australia. Other coal producers may also develop or acquire new projects to increase their coal production, which may adversely impact our competitiveness. Some of our global competitors have significantly greater financial resources, such that increases in their coal production may affect domestic and foreign Met coal supply into the seaborne market and associated prices and impact our ability to retain or attract Met coal customers. In addition, our ability to ship our Met coal to non-U.S. and non-Australian customers depends on port and transportation capacity. Increased competition within the Met coal industry for international sales could result in us not being able to obtain throughput capacity at port facilities, as well as transport capacity, and could cause the rates for such services to increase to a point where it is not economically feasible to export our Met coal.

Increased competition, or a failure to compete effectively, in the markets in which we participate may result in a loss of market share and could adversely affect our financial condition and results of operations.

Demand for our Met coal is significantly dependent on the steel industry.

The majority of the coal that we produce is Met coal that is sold, directly or indirectly, to steel producers and is used in blast furnaces for steel production. Met coal, specifically high-quality HCC and low-volatile PCI, which is produced at most of our assets, has specific physical and chemical properties, which are necessary for efficient blast furnace operation. Therefore, demand for our Met coal is correlated to demands of the steel industry. The steel industry’s demand for Met coal is influenced by a number of factors, including: the cyclical nature of that industry’s business; general economic and regulatory conditions and demand for steel; and the availability, cost and preference for substitutes for steel, such as aluminum, composites and plastics, all of which may impact the demand for steel products. Similarly, if new steelmaking technologies or practices are developed that can be substituted for Met coal in the integrated steel mill process, then demand for Met coal would be expected to decrease.

Although conventional blast furnace technology has been the most economic large-scale steel production technology for a number of years, there can be no assurance that over the longer term, competitive technologies not reliant on Met coal would not emerge, which could reduce the demand and price premiums for Met coal. A significant reduction in the demand for steel products would reduce the demand for Met coal, which could have a material adverse effect on our financial condition and results of operations.

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Additionally, tariffs imposed by the United States on the import of certain steel products may impact foreign steel producers to the extent their production is imported into the United States. In March 2018, the United States established a 25% tariff on imports of steel into the United States, which adversely impacted the economic value of coal previously sourced for sale in China. Future tariffs could further reduce imports of steel and increase U.S. Met coal demand. This additional U.S. Met coal demand could be met by reducing exports of Met coal and redirecting that volume to domestic consumption.

In May 2019, the United States agreed to lift the steel and aluminum tariffs on Mexico and Canada. Currently, Argentina, Australia, Brazil, Canada, Mexico and South Korea are exempt from the additional tariffs on derivative steel products, while Argentina, Australia, Canada and Mexico are exempt from the additional duties on derivative aluminum products.

The tariffs established by the United States have prompted retaliatory tariffs from key trading partners, notably Europe and China. Any further retaliatory tariffs by these or other countries to these tariffs may limit international trade and adversely impact global economic conditions. We cannot ascertain the impact, if any, that similar tariffs may have on demand for our Met coal. See “—We may face restricted access to international markets in the future.”

In addition, we cannot anticipate the impact the COVID-19 pandemic will continue to have on steel production in Japan, Korea, Taiwan, India, Europe, Brazil, China and North America. A significant reduction in steel production would reduce the demand for Met coal, which could have a material adverse effect in our financial condition and results of operations.

We may face restricted access to international markets in the future.

Access to international markets may be subject to ongoing interruptions and trade barriers due to policies and tariffs of individual countries, and the actions of certain interest groups to restrict the import or export of certain commodities. For example, the current imposition of tariffs and import quota restrictions by China on U.S. and Australian coal imports respectively, including the ongoing suspension of imports of Australian coal into China, may in the future have a negative impact on our profitability. The timing of any change to these measures remains uncertain, and there can be no guarantee that other tariffs, import quota restrictions, bans or other trade barriers will not be imposed (whether as a result of geo-political tensions or for other reasons), either by China or in other markets for our products. We may or may not be able to access alternate markets for our coal should additional interruptions and trade barriers occur in the future. An inability for Met coal suppliers to access international markets, including China, would likely result in an oversupply of Met coal and may result in a decrease in prices or the curtailment of production, which could have a material adverse effect on our financial condition and results of operations.

If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.

Our mining operations produce coal, which is transported to customers by a combination of road, rail, barge and ship. The delivery of coal produced by our mining operations is subject to potential disruption and competition from other network users, which may affect our ability to deliver coal to our customers and may have an impact on productivity and profitability. Such disruptions to transportation services may include, among others:

•disruptions due to weather-related problems;

•key equipment or infrastructure failures;

•industrial action;

•rail or port capacity congestion or constraints;

•commercial disputes;

•failure to obtain consents from third parties for access to rail or land, or access being removed or not granted by regulatory authorities;

•changes in applicable regulations;

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•failure or delay in the construction of new rail or port capacity; and

•terrorist attacks, natural disasters, the impact from the ongoing COVID-19 pandemic or other events.

Any such disruptions, or any deterioration in the reliability of services provided by our transportation service providers, could impair our ability to supply coal to our customers, result in decreased shipments and revenue and adversely affect our results of operations.

Typically, we sell coal at the mine gate and/or loaded into vessels at the port. While ordinarily our coal customers arrange and pay for transportation of coal from the mine or port to the point of use, we have entered into arrangements with third parties to gain access to transportation infrastructure and services where required, including road transport organizations, rail carriers and port owners. Where coal is exported or sold other than at the mine gate, the costs associated with these arrangements represent a significant portion of both the total cost of supplying coal to customers and of our production costs. As a result, the cost of transportation is not only a key factor in our cost base, but also in the purchasing decision of customers. Transportation costs may increase and we may not be able to pass on the full extent of cost increases to our customers. For example, where transportation costs are connected to market demand, costs may increase if usage by us and other market participants increases. Significant increases in transport costs due to factors such as fluctuations in the price of diesel fuel, electricity and demurrage or environmental requirements could make our coal less competitive when compared to coal produced from other regions and countries. As the transportation capacity secured by our port and rail agreements is based on assumed production volumes, we may also have excess transportation capacity (which, in the case of take-or-pay agreements, we may have to pay for even if unused) if our actual production volumes are lower than our estimated production volumes. Conversely, we may not have sufficient transportation capacity if our actual production volumes exceed our estimated production volumes, if we are unable to transport the full capacity due to contractual limitations or if any deterioration in our relationship with brokers and intermediaries results in a reduction in the proportion of coal purchased FOR from our U.S. Operations (and a corresponding increase in the proportion of coal purchased FOB).

Take-or-pay arrangements within the coal industry could unfavorably affect our profitability.

Our Australian Operations generally contract port and rail capacity via long-term take-or-pay contracts for transport, currently with Aurizon Operations Limited and Pacific National Pty Ltd, to and export from the Port of Gladstone via two main port terminals, RGTCT and WICET. At our U.S. Operations, we also have a take-or-pay agreement in connection with the Kinder Morgan Pier IX Terminal in Hampton Roads, Virginia. We may enter into other take-or-pay arrangements in the future.

Where we have entered into take-or-pay contracts, we will generally be required to pay for our contracted port or rail capacity, even if it is not utilized by us or other shippers. Although the majority of our take-or-pay arrangements provide security over minimum port and rail infrastructure availability, unused port or rail capacity can arise as a result of varying unforeseen circumstances, including insufficient production from a given mine, a mismatch between the timing of required port and rail capacity for a mine, or an inability to transfer the used capacity due to contractual limitations, such as required consent of the provider of the port or rail services, or because the coal must emanate from specified source mines or be loaded onto trains at specified load points. Paying for unused transport capacity could materially and adversely affect our cost structures and financial performance. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a summary of our expected future obligations under take-or-pay arrangements as of December 31, 2021.

A decrease in the availability or increase in costs of key supplies, capital equipment, commodities and purchased components, such as diesel fuel, steel, explosives and tires could materially and adversely affect our financial condition and results of operations.

Our mining operations require a reliable supply of large quantities of fuel, explosives, tires, steel-related products (including roof control materials), lubricants and electricity. The prices we pay for commodities are strongly impacted by the global market. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. If the cost of any of these key supplies or commodities increased significantly, or if a source for these supplies or mining equipment was unavailable to meet our replacement demands, including as a result of the COVID-19 pandemic or otherwise, our profitability could be reduced or we could experience a delay or halt in our production.

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Our coal production and production costs can be materially and adversely impacted by unexpected shortages or increases in the costs of consumables, spare parts, plant and equipment. For example, operation of the thermal dryer located at the CPP at Buchanan is dependent upon the delivery of natural gas and there is currently only one natural gas supplier in the area, an affiliate of CONSOL Energy. Although we have entered into a gas purchase agreement with CONSOL Energy, this agreement can be terminated by CONSOL Energy on 30 days’ notice and any delay or inability to negotiate a replacement agreement would impact our costs of production as we would need to change our processing method at Buchanan.

Defects in title or loss of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs.

In Queensland, where all of our Australian Operations are carried out, exploring or mining for coal is unlawful without a tenement granted by the Queensland government. The grant and renewal of tenements are subject to a regulatory regime and each tenement is subject to certain conditions. There is no certainty that an application for the grant of a new tenement or renewal of one of the existing Tenements at Curragh will be granted at all or on satisfactory terms or within expected timeframes. Further, the conditions attached to the Tenements may change at the time they are renewed. There is a risk that we may lose title to any of our granted Tenements if we fail to comply with the Tenement conditions and other applicable legislative requirements (including payment of State royalties) or if the land that is subject to the title is required for public purposes. The Tenements have expiration dates ranging from May 31, 2023 to July 31, 2044 and, where renewal is required, there is a risk that the Queensland government may change the terms and conditions of such Tenement upon renewal.

In the United States, title to a leased property and mineral rights is generally secured prior to permitting and developing a property. In some cases, we rely on title information or representations and warranties provided by our lessors, grantors or other third parties. Our right to mine some of our reserves may be adversely affected if defects in title or boundaries exist or if a lease expires. Any challenge to our title or leasehold interests could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property and, accordingly, require us to reduce our estimated coal reserves. In addition, if we mine on property that we do not own or lease, we could incur civil damages or liability for such mining and be subject to conversion, negligence, trespass, regulatory sanction and penalties. Some leases have minimum production requirements or require us to commence mining operations in a specified term to retain the lease. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself.

In the United States, we predominantly access our mining properties through leases with a range of private landholders. If a default under a lease for properties on which we have mining operations resulted in the termination of the applicable lease, we may have to suspend mining or significantly alter the sequence of such mining operations, which may adversely affect our future coal production and future revenues.

To obtain leases or mining contracts to conduct our U.S. Operations on properties where defects exist or to negotiate extensions or amendments to existing leases, 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.

A defect in our title or the loss of any lease or Tenement upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves or process the coal we mine.

We may be unable to obtain, renew or maintain permits necessary for our operations, which would reduce coal production, cash flows and profitability.

Our performance and operations depend on, among other things, being able to obtain on a timely basis, and maintain, all necessary regulatory approvals, including any approvals arising under applicable mining laws, environmental regulations and other laws, for our current operations, expansion and growth projects. Examples of regulatory approvals that we must obtain and maintain include mine development approvals, environmental permits and, in Australia, tenure and approvals relating to native title and indigenous cultural heritage. In addition, our operations depend on our ability to obtain and maintain consents from private land owners and good relations with local communities.

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The requirement to obtain and maintain approvals and address potential and actual issues for former, existing and future mining projects is common to all companies in the coal sector. However, there is no assurance or guarantee that we will obtain, secure, or be able to maintain any or all of the required consents, approvals and rights necessary to maintain our current production profile from our existing operations or to develop our growth projects in a manner which will result in profitable mining operations and/or achieve our long-term production targets. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to the interpretation of the regulators that enforce them, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations. Certain laws, such as the SMCRA, require that certain environmental standards be met before a permit is issued. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements. These comments are prepared in connection with applicable regulatory processes, and the public may otherwise engage in the permitting process, including bringing lawsuits to challenge the issuance of permits, the validity or adequacy of environmental impact statements or performance of mining activities. In states where we operate, applicable laws and regulations also provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls or is under common ownership or control with us have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. Thus, past or ongoing violations of federal and state mining laws by us or such entity could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive activism and litigation by environmental groups. If this trend continues, it could materially and adversely affect our mining operations, development and expansion and cost structures, the transport of coal and our customers’ ability to use coal produced by our mines, which, in turn, could have a material adverse effect on our financial condition and results of operation.

In particular, certain of our activities require a dredge and fill permit from the USACE under Section 404 of the CWA. In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements and a series of court challenges, which have resulted in increased costs and delays in the permitting process. In addition, in 2015, the EPA and the USACE issued the CWR, under the CWA that would further expand the circumstances when a Section 404 permit is needed. The CWR is the subject of extensive ongoing litigation and administrative proceedings, as a result of which the CWR has been enjoined in certain states (including West Virginia) and reinstated in others (including Virginia and Pennsylvania), and its current and future impact on our operations are the subject of significant uncertainty. On April 21, 2020, the EPA and the USACE published the NWPR, replacing the CWR. The NWPR revises the definition of waters of the United States and replaces the CWR. The NWPR shrinks the agencies’ jurisdiction, particularly as it relates to tributaries and adjacent waters, such as wetlands, that were previously covered by the definition under the CWR. The NWPR went into effect on June 22, 2020. States and environmental groups have filed challenges to the NWPR in various federal district courts. We cannot at this time predict how this rule will be enforced in the future.

Additionally, we may rely on nationwide permits under the CWA Section 404 program for some of our operations. These nationwide permits are issued every five years, and the 2017 nationwide permit program was recently reissued in January 2017. If we are unable to use the nationwide permits and require an individual permit for certain work, that could delay operations.

If we are unable to obtain and maintain the approvals, consents and rights required for our current and future operations, or if we obtain approvals subject to conditions or limitations, the economic viability of the relevant projects may be adversely affected, which may in turn result in the value of the relevant assets being impaired, which could have a material adverse effect on our financial condition and results of operations.

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A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity.

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. Any reduced availability or future shortage of skilled labor in the Australian and U.S. mining industries (including, but not limited to, ongoing labor shortage at the Logan operations which has impacted production at our U.S. Operations and as a result of the impact of COVID-19 pandemic) could result in our having insufficient personnel to operate our business, or expand production, particularly in the event there is an increase in the demand for our coal, which could adversely affect our financial condition and results of operations.

Decreases in demand for coal-fired electricity and changes in thermal coal consumption patterns of the United States and Australian electric power generators could adversely affect our business.

In addition to Met coal, our Australian Operations and U.S. Operations produce some thermal coal. Sales of thermal coal represented 27.7% of tons sold by our Australian Operations and 8.4% of our total revenues for the year ended December 31, 2021. The majority of the thermal coal produced by our Australian Operations is sold on a long-term supply arrangement to Stanwell. Sales of thermal coal by our Australian Operations to domestic and export buyers are exposed to fluctuations in the global demand for thermal coal or electricity. However, coal sold to Stanwell is not directly exposed to fluctuations in the global demand for electricity or thermal coal. Under the Stanwell supply contract, Stanwell can set volumes, and pricing is set at significantly below-market rates. Our cost of supplying coal to Stanwell has been and may continue to be greater than the price paid by Stanwell. See “—Risks related to the Supply Deed with Stanwell may adversely affect our financial condition and results of operations.”

For the year ended December 31, 2021, sales of thermal coal represented 2.8% of tons sold by our U.S. Operations and 0.8% of our total revenues for the year ended December 31, 2021. As such, any changes in coal consumption by electric power generators in the United States could impact our business over the long term.

While power generation from thermal coal remains a cost-effective form of energy, the increasing focus on renewable energy generation, competition from alternative fuel sources, such as natural gas, environmental regulations and the consequential decline in electricity generation from fossil fuels, is expected to result in the further decline of coal-fired electricity generation due to retirement of coal-fired capacity in favor of alternative energy. The low price of natural gas in years preceding the COVID-19 pandemic has resulted in some U.S. electric power generators increasing natural gas consumption while decreasing coal consumption.

Further reductions in the demand for coal-fired electricity generation and the growth of alternative energy options, such as renewables, and alternate power generation technologies, as well as any reduction in demand for electricity generally as a result of the impact of the ongoing COVID-19 pandemic could materially reduce the demand for thermal coal, which may have a material adverse effect on our financial condition and results of operations.

The existence (or claimed existence) of native title on land within our Australian tenements may impose restrictions on the construction of our expansion activities and our continued operations.

In Australia, mineral exploration and mining tenure (and many other forms of tenure or interests in land) may cover land that is subject to a claim for native title or land where native title has already been determined to exist. Native title is the communal, group or individual rights and interests of Aboriginal or Torres Strait Islander people in relation to their traditional land or waters. The existence of native title in Australia is recognized and protected in accordance with the Native Title Act 1993 (Cth), or the Native Title Act, and legislation in each State and Territory. The common law of Australia recognizes a form of native title that, in circumstances where it has not been extinguished, reflects the entitlement of the appropriate traditional owners to their lands, in accordance with their traditional law and custom.

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If native title is either determined to exist or there are registered, but undetermined, native title claims over any part of the tenements and native title has not otherwise been extinguished with respect to that part, we may be required to negotiate with, and pay compensation to, the native title holders for impairment, loss or diminution or other effect of the proposed activities on their native title rights and interests. Compensation obligations may also arise pursuant to agreements with native title claimants or native title holders in relation to any tenements we acquire. The existence of native title or a registered native title claim may preclude or delay the granting of exploration and mining tenements pending resolution of the statutory procedures imposed by the Native Title Act and considerable expenses may be incurred in negotiating and resolving native title issues.

The risk of unforeseen native title claims also could affect existing operations as well as development projects. Although native title will not prevent the exercise of any validly granted rights and interests under our tenements, the Native Title Act and applicable State and Commonwealth legislation, together with the recognition of native title at common law, may impact the continued operations under our tenements, development projects and the construction of our expansion activities and/or give rise to liability for compensation.

The Aboriginal Cultural Heritage Act 2003 (Qld) and the Torres Strait Islander Cultural Heritage Act 2003 (Qld) provide a framework for the protection of Aboriginal and Torres Strait Islander cultural heritage. The main mechanism through which each act operates is a list of places and artifacts of heritage significance. The acts also create offenses such as breach of the cultural heritage duty of care. This duty of care requires a person carrying out an activity to take all reasonable and practicable measures to ensure the activity does not harm Aboriginal cultural heritage.

In addition, it may also be necessary for us to enter into separate arrangements with the traditional owners of the sites. This could be costly for us and potentially cause delays in our continued operational and expansion activities.

Although the failure to resolve any issues associated with sites of indigenous heritage significance could adversely impact our expansion activities and our continuing operations, there are no such current or anticipated issues.

Operational and Technology Risks

Risks inherent to mining operations could impact the amount of coal produced, cause delay or suspend coal deliveries, or increase the cost of operating our business.

Our mining operations, including exploration, development, preparation, product handling and accessing transport infrastructure, may be affected by various operational difficulties that could impact the amount of coal produced at our coal mines, cause delay or suspend coal deliveries, or increase the cost of mining for a varying length of time. Our financial performance is dependent on our ability to sustain or increase coal production and maintain or increase operating margins. Our coal production and production costs are, in many respects, subject to conditions and events beyond our control, which could disrupt our operations and have a significant impact on our financial results. Adverse operating conditions and events that we may have experienced in the past or may experience in the future include:

•a failure to achieve the Met qualities anticipated from exploration activities;

•variations in mining and geological conditions from those anticipated, such as variations in coal seam thickness and quality, and geotechnical conclusions;

•operational and technical difficulties encountered in mining, including equipment failure, delays in moving longwall equipment, drag-lines and other equipment and maintenance or technical issues;

•adverse weather conditions or natural or man-made disasters, including hurricanes, cyclones, tornadoes, floods, droughts, bush fires, seismic activities, ground failures, rock bursts, structural cave-ins or slides and other catastrophic events (such as the ongoing COVID-19 pandemic that has caused significant disruption across nearly all industries and markets, including global supply chain shortages, the impact of which, continues to be uncertain);

•insufficient or unreliable infrastructure, such as power, water and transport;

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•industrial and environmental accidents, such as releases of mine-affected water and diesel spills (both of which have affected our Australian Operations in the past);

•industrial disputes and labor shortages;

•mine safety accidents, including fatalities, fires and explosions from methane and other sources;

•competition and conflicts with other natural resource extraction and production activities within overlapping operating areas, such as natural gas extraction or oil and gas development;

•unexpected shortages, or increases in the costs, of consumables, spare parts, plant and equipment;

•cyber-attacks that disrupt our operations or result in the dissemination of proprietary or confidential information about us to our customers or other third parties; and

•security breaches or terrorist acts.

If any of the foregoing conditions or events occurs and is not mitigated or excusable as a force majeure event under our coal sales contracts, any resulting failure on our part to deliver coal to the purchaser under such contracts could result in economic penalties, demurrage costs, suspension or cancellation of shipments or ultimately termination of such contracts, which could have a material adverse effect on our financial condition and results of operations.

Our U.S. Operations are concentrated in a small number of mines in the CAPP and our Australian Operations include one mine in the Bowen Basin of Australia. As a result, the effects of any of these conditions or events may be exacerbated and may have a disproportionate impact on our results of operations and assets. Any such operational conditions or events could also result in disruption to key infrastructure (including infrastructure located at or serving our mining activities, as well as the infrastructure that supports freight and logistics). These conditions and events could also result in the partial or complete closure of particular railways, ports or significant inland waterways or sea passages, potentially resulting in higher costs, congestion, delays or cancellations on some transport routes. Any of these conditions or events could adversely impact our business and results of operations.

Our long-term success depends upon our ability to continue discovering, or acquiring and developing assets containing, coal reserves that are economically recoverable.

Our recoverable reserves decline as we produce coal. Our long-term outlook depends on our ability to maintain a commercially viable portfolio of coal reserves that are economically recoverable. Failure to acquire or discover new coal reserves or develop new assets could negatively affect our financial condition and results of operations. Exploration activity may occur adjacent to established assets and in new regions. These activities may increase land tenure, infrastructure and related political risks. Failure to discover or acquire new coal reserves, replace coal reserves or develop new assets or operations in sufficient quantities to maintain or grow the current level of reserves could negatively affect our financial condition and results of operations.

Potential changes to our portfolio of assets through acquisitions and divestments may have an adverse effect on future results of operations and financial condition. From time to time, we may add assets to, or divest assets from, our portfolio. There are a number of risks associated with historical and future acquisitions or divestments, including, among others:

•adverse market reaction to such acquisitions and divestments or the timing or terms on which acquisitions and divestments are made;

•imposition of adverse regulatory conditions and obligations;

•political and country risk;

•commercial objectives not being achieved as expected;

•unforeseen liabilities arising from changes to the portfolio;

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•sales revenues and operational performance not meeting expectations;

•anticipated synergies or cost savings being delayed or not being achieved; and

•inability to retain key staff and transaction-related costs being more than anticipated.

These factors could materially and adversely affect our financial condition and results of operations.

We rely on estimates of our recoverable resources and reserves, which are complex due to geological characteristics of the properties and the number of assumptions made.

We rely on estimates of our recoverable resources and reserves. In this Annual Report on Form 10-K, we report our estimated resources and reserves in accordance with subpart 1300 of Regulation S-K under the Exchange Act. See Item 2. “Properties.” These requirements differ significantly from the previously applicable disclosure requirements of SEC industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral resources, in addition to our mineral reserves. In addition, as an ASX-listed company, our ASX disclosures follow the Australian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves 2012, or the JORC Code. Accordingly, our estimates of resources and reserves in this Annual Report on Form 10-K and in other reports that we are required to file with the SEC may be different than our estimates of resources and reserves as reported in our ASX disclosures.

Coal is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which our coal is economically recoverable varies based on the mine. We base our resource and reserve information on geologic data, coal ownership information and current and proposed mine plans, and mining cost assumptions may be affected by changes in mine planning or scheduling over time. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. There are inherent uncertainties and risks associated with such estimates, including:

•geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience and assumptions in areas we currently mine;

•current and future market prices for coal, contractual arrangements, operating costs and capital expenditures;

•severance and excise taxes, unexpected governmental taxes, royalties, stamp duty and development and reclamation costs;

•future mining technology improvements;

•the effects of regulation by governmental agencies;

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

•employee health and safety; and

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

Except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Even if a mineral resource exists, there can be no assurance that any part of such mineral resource will ever be converted to mineral reserves.

In addition, estimates of coal resources and reserves are revised based on actual production experience, and/or new exploration information and therefore the estimates of coal resources and reserves are subject to change. Should we encounter geological conditions or qualities different from those predicted by past drilling, sampling and similar examinations, estimates of coal resources and reserves may have to be adjusted and mining plans, coal processing and infrastructure may have to be altered in a way that might adversely affect our operations. As a result, our estimates may not accurately reflect our actual future coal resources and reserves.

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As a result, the quantity and quality of the coal that we recover may be less than the resource and reserve estimates included in this Annual Report on Form 10-K. If our actual coal resources and reserves are less than current estimates, or the rate at which they are recovered is less than estimated or results in higher than estimated cost, our financial condition and results of operations may be materially adversely affected.

Our profitability could be affected adversely by the failure of suppliers and/or outside contractors to perform.

We use contractors and other third parties for exploration, mining and other services generally, and are reliant on several third parties for the success of our current operations and the development of our growth projects. While this is normal for the mining industry, problems caused by third parties may arise, which may have an impact on our performance and operations. In particular, the majority of workers at our Australian Operations are employed by contractors, including Thiess, Golding Contractors Pty Ltd, and Wolff Mining Pty Ltd.

Operations at our mines may be interrupted for an extended period in the event that we lose any of our key contractors (because their contract is terminated or expires) and are required to replace them. There can be no assurance that skilled third parties or contractors will continue to be available at reasonable rates. As we do not have the same control over contractors as we do over employees, we are also exposed to risks related to the quality or continuation of the services of, and the equipment and supplies used by, our contractors, as well as risks related to the compliance of our contractors with environmental and health and safety legislation and internal policies, standards and processes. Any failure by our key contractors to comply with their obligations under our operating agreements with them (whether as a result of financial, safety or operational difficulties or otherwise), any termination or breach of our operating agreements by our contractors, any protracted dispute with a contractor, any inability to perform due to the impact of the ongoing COVID-19 pandemic, any material labor dispute between our contractors and their employees or any major labor action by those employees against our contractors, could have a material adverse effect on our financial condition and results of operations.

Further, in periods of high commodity prices, demand for contractors may exceed supply resulting in increased costs or lack of availability of key contractors. Disruptions of operations or increased costs also can occur as a result of disputes with contractors or a shortage of contractors with particular capabilities. To the extent that any of the foregoing risks were to materialize, our operating results and cash flows could be adversely affected.

Our inability to replace or repair damaged or destroyed equipment or facilities in a timely manner could materially and adversely affect our financial condition and results of operations.

We depend on several major pieces of mining equipment and facilities to produce and transport coal, including, but not limited to, longwall mining systems, continuous miners, draglines, dozers, excavators, shovels, haul trucks, conveyors, CPPs and rail loading and blending facilities. Obtaining and repairing these major pieces of equipment often involves long lead times. If any of these pieces of equipment and facilities suffers major damage or is destroyed by fire, abnormal wear and tear, 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 could materially and adversely affect our financial condition and results of operations. Our ability to replace or repair damaged or destroyed equipment or facilities may also be dependent on suppliers or manufactures remaining operational and having the relevant equipment, work force or services available for us. Suppliers and manufactures may be unable to provide such equipment, work force or service for a range of reasons, including but not limited to their business suffering adverse effects as a result of the ongoing COVID-19 pandemic.

Additionally, regulatory agencies sometimes make changes with regard to requirements for pieces of equipment. Such changes can impose costs on us and can cause delays if manufacturers and suppliers are unable to make the required changes in compliance with mandated deadlines.

Our ability to operate effectively could be impaired if we lose key personnel or fail to attract qualified personnel.

The loss of key personnel and the failure to recruit sufficiently qualified staff could affect our future performance. We have entered into employment contracts with a number of key personnel in Australia and the United States, including our Managing Director and Chief Executive Officer, Garold Spindler, our Chief Operating Officer U.S., Jeffrey Bitzer, and our Chief Operating Officer, Australia, Douglas Thompson.

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Mr. Spindler’s, Mr. Bitzer’s and Mr. Thompson’s expertise and experience in the mining industry are important to the continued development and operation of our mining interests. However, there is no assurance that such personnel will remain with us for the term of their employment contracts or beyond. In the United States, we have not entered into employment contracts with any of our key personnel (other than Mr. Spindler, Mr. Bitzer and their direct reports), meaning that we do not have the benefit of notice provisions or non-compete restraints with these employees. There may be a limited number of persons with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled personnel with coal industry experience in Australia and the United States. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. The loss of such key personnel or the failure to recruit sufficiently qualified employees may affect our business and future performance.

In times of drought and/or shortage of available water, our operations and production, particularly at Curragh, could be negatively impacted if the regulators impose restrictions on our water offtake licenses that are required for water used in the CPPs.

In Queensland, all entitlements to the use, control and flow of water are vested in the state and regulated by the Water Act 2000 (Qld). Allocations under the Water Act 2000 (Qld) can be managed by a water supply scheme operator, such as SunWater Ltd. We have purchased the required water allocations for Curragh and entered into a suite of related channel and pipeline infrastructure agreements and river supply agreements with SunWater Ltd. to regulate the supply of water pursuant to these allocations.

The amount of water that is available to be taken under a water entitlement will vary from year to year and is determined by water sharing rules of the relevant catchment area. These rules will, for example, state a procedure for water supply scheme holders to calculate the water available to an allocation holder, based on available and predicted supply. In situations of severely constrained supply (such as during a drought), supply contracts with the scheme operator generally provide for a reduced apportionment, with certain uses (e.g., domestic use) being given higher priority. It is possible that during times of drought our water offtake entitlements in Australia could be reduced. If our water offtake entitlement was reduced, the operations would have to recycle more of the water collected in on-site dams and former mining pits, from rainfall and dewatering activities, for use in the Curragh CPPs. This may impact our ability to maintain current production levels without incurring additional costs, which could adversely impact our operations and production.

We may not have adequate insurance coverage for some business risks.

We have insurance coverage for certain operating risks that provide limited coverage for some potential liabilities associated with our business. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. In addition, we may become subject to liability (including in relation to pollution, occupational illnesses or other hazards), or suffer loss resulting from business interruption, for which we are not insured (or are not sufficiently insured) or cannot insure, including liabilities in respect of past activities.

Should we suffer a major uninsured loss, future financial performance could be materially adversely affected. In addition, insurance may not continue to be available at economically acceptable premiums or coverage may be reduced. As a result, the insurance coverage may not cover the full scope and extent of claims against us or losses we may incur. The occurrence of a significant adverse event not fully or partially covered by insurance could have a material adverse effect on our financial condition and results of operations.

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Cybersecurity attacks, natural disasters, terrorist attacks and other similar crises or disruptions may negatively affect our business, financial condition and results of operations.

Our business may be impacted by disruptions such as cybersecurity attacks or failures, threats to physical security, and extreme weather conditions or other natural disasters. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cybersecurity attacks than other targets in the United States or Australia. These disruptions or any significant increases in energy prices that follow could result in government-imposed price controls. Our insurance may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

In addition, a disruption in, or failure of, our information technology systems could adversely affect our business operations and financial performance. We rely on the accuracy, capacity and security of our information technology, or IT, systems for the operations of many of our business processes and to comply with regulatory, legal and tax requirements. While we maintain some of our critical IT systems, we are also dependent on third parties to provide important IT services relating to, among other things, human resources, electronic communications and certain finance functions. Despite the security measures that we have implemented, including those related to cybersecurity, our systems could be breached or damaged by computer viruses, natural or man-made incidents or disasters or unauthorized physical or electronic access. Though we have controls in place, we cannot provide assurance that a cyber-attack will not occur.

Furthermore, we may have little or no oversight with respect to security measures employed by third-party service providers, which may ultimately prove to be ineffective at countering threats. Failures of our IT systems, whether caused maliciously or inadvertently, may result in the disruption of our business processes, the unauthorized release of sensitive, confidential or otherwise protected information or the corruption of data, which could adversely affect our business operations and financial performance. We may be required to incur significant costs to protect against and remediate the damage caused by such disruptions or system failures in the future.

Mining in the CAPP is more complex and involves more regulatory constraints than mining in other areas of the U.S., which could affect our mining operations and cost structures in these areas.

Mining in the CAPP is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas. The geological characteristics of coal reserves in the CAPP, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available or, if available, may not be able to be mined at costs comparable to those of the depleting mines. In addition, compared to mines in the other areas of the United States, permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mining properties in the CAPP.

Financial and Strategic Risks

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

For the year ended December 31, 2021, our top ten customers comprised 68.7% of our total revenue and our top five customers comprised 46.3% of our total revenue. For the year ended December 31, 2021, sales to Xcoal and Tata Steel represented approximately 11.2% and 16.7%, respectively, of our total revenue. The majority of our sales are made on a spot basis or under contracts with terms of typically one year. The failure to obtain additional customers or the loss of all or a portion of the revenues attributable to any customer as a result of competition, creditworthiness, inability to negotiate extensions, replacement of contracts or the impact of the ongoing COVID-19 pandemic or otherwise, may adversely affect our business, financial condition and results of operations.

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If a substantial number of our customers fail to perform under our contracts with them, our revenues and operating profits could suffer.

A significant portion of the sales of our Met coal is to customers with whom we have had long-term relationships. The success of our business depends on our ability to retain our current customers, renew our existing customer contracts and solicit new customers. Our ability to do so generally depends on a variety of factors, including having our mines operational, having the type and quantity of coal available, the quality and price of our products, our ability to market these products effectively, our ability to deliver on a timely basis and the level of competition that we face.

In addition, our sales contracts generally contain provisions that allow customers to suspend or terminate if we commit a material breach of the terms of the contract, a change in law restricts or prohibits a party from carrying out its material obligations under the contract or a material adverse change occurs in our financial standing or creditworthiness. If customers suspend or terminate existing contracts, or otherwise refuse to accept shipments of our Met coal for which they have an existing contractual obligation, our revenues will decrease, and we may have to reduce production at our mines until our customers’ contractual obligations are honored.

If our customers do not honor contract commitments, or if they terminate agreements or exercise force majeure provisions allowing for the temporary suspension of performance during specified events beyond the parties’ control, including the ongoing COVID-19 pandemic and we are unable to replace the contract, our financial condition and results of operations could be materially and adversely affected.

If our ability to collect payments from customers is impaired, our revenues and operating profits could suffer.

Our ability to receive payment for coal sold and delivered will depend on the continued contractual performance and creditworthiness of our customers and counterparties. For certain customers, we require the provision of a letter of credit as security for payment. A sustained payment default by one or more of our largest customers could have a material adverse effect on our financial condition and results of operations. The inability of key customers to procure letters of credit (due to general economic conditions or the specific circumstances of the customer) may restrict our ability to contract with such customers or result in fewer sales contracts being executed, which could materially adversely affect our financial condition and results of operations. For certain of our large customers in Australia who have not provided letters of credit or other form of security, we maintain an insurance policy to cover for any failure in payment.

If non-payment occurs, we may decide to sell the customer’s Met coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. If our customers’ or counterparties’ creditworthiness deteriorates, our business could be adversely affected.

Changes in credit ratings issued by nationally recognized statistical rating organizations could adversely affect our cost of financing and the market price of our securities.

Credit rating agencies could downgrade our ratings due to factors specific to our business, a prolonged cyclical downturn in the mining industry or macroeconomic trends (such as global or regional recessions) and trends in credit and capital markets more generally. Any decline in our credit ratings would likely result in an increase to our cost of financing, limit our access to the capital markets, significantly harm our financial condition and results of operations, hinder our ability to refinance existing indebtedness on acceptable terms and have an adverse effect on the market price of our securities.

Our existing and future indebtedness may limit cash flow available to invest in the ongoing needs of our businesses, which could prevent us from fulfilling our obligations under our senior secured notes, senior secured asset-based revolving credit agreement in an initial aggregate principal amount of $100.0 million, or the ABL Facility, and other debt, and we may be forced to take other actions to satisfy our obligations under our debt, which may not be successful.

As of December 31, 2021, we had $315.0 million aggregate principal amount of secured long-term debt outstanding. As of December 31, 2021, no amounts were outstanding, and no outstanding letters of credit issued under the ABL Facility. As of December 31, 2021, the available borrowing capacity under our ABL Facility was $100.0 million.

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We dedicate a portion of our cash flow from operations to the payment of debt service, reducing the availability of our cash flow to fund capital expenditures, acquisitions or strategic development initiatives and other general corporate purposes. Our ability to make scheduled payments on or to refinance our debt obligations depends on our ability to generate cash in the future and our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control, including the impact of the COVID-19 pandemic. There can be no assurance that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our debt. In addition, any failure to comply with covenants in the instruments governing our debt could result in an event of default that, if not cured or waived, would have a material adverse effect on us.

Our level of indebtedness could have further consequences, including, but not limited to, increasing our vulnerability to adverse economic or industry conditions, placing us at a competitive disadvantage compared to other businesses in the industries in which we operate that are not as leveraged and that may be better positioned to withstand economic downturns, limiting our flexibility to plan for, or react to, changes in our businesses and the industries in which we operate, and requiring us to refinance all or a portion of our existing debt. We may not be able to refinance on commercially reasonable terms or at all, and any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, making it more difficult to obtain surety bonds, letters of credit or other financial assurances that may be demanded by our vendors or regulatory agencies, particularly during periods in which credit markets are weak.

A portion of our borrowing capacity and outstanding indebtedness bears interest at a variable rate based on the London Interbank Offered Rate, or LIBOR. U.S-dollar LIBOR must be replaced before June 30, 2023. The Alternative Reference Rates Committee has proposed the Secured Overnight Financing Rate, or SOFR, as its recommended alternative to LIBOR. It is uncertain at this time, however, what the potential impact of the transition from LIBOR as an interest rate benchmark to other potential alternative reference rates, including SOFR, may be on our financial condition and results of operations. See “—Interest rates could change substantially and have an adverse effect on our profitability.”

If we are unable to service our debt obligations, we could face substantial liquidity problems and we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital, including additional secured or unsecured debt, or restructure or refinance our debt, and we may be unable to continue as a going concern. We may be unable to consummate any proposed asset sales or recover the carrying value of these assets, and any proceeds may not be adequate to meet any debt service obligations then due. Any of these examples potentially could have a material adverse impact on our results of operations, profitability, stockholders’ equity and capital structure.

We adjust our capital structure from time to time and may need to increase our debt leverage, which would make us more sensitive to the effects of economic downturns.

It is possible that we may need to raise additional debt or equity funds in the future. Our ABL Facility and operating cash flows may not be adequate to fund our ongoing capital requirements, for any future acquisitions or projects or to refinance our debt. There is no guarantee that we will be able to refinance our existing debt, or if we do, there is no guarantee that such new funding will be on terms acceptable to us.

Global credit markets have been severely constrained in the past, such as during a global financial crisis and the European sovereign debt crisis, and during the ongoing COVID-19 pandemic, and the ability to obtain new funding or refinance in the future may be significantly reduced. If we are unable to obtain sufficient funding, either due to banking and capital market conditions, generally, or due to factors specific to our business, we may not have sufficient cash to meet our ongoing capital requirements, which in turn could materially and adversely affect our financial condition. Failure to obtain sufficient financing could cause delays or abandonment of business development plans and have a material adverse effect on our business, operations and financial condition.

Recently, certain financial institutions, investment managers and insurance companies globally have responded to pressure to take actions to limit or divest investments in, financing made available to, and insurance coverage provided for, the development of new coal-fired power plants and coal miners that derive revenues from thermal coal sales. For example, in 2017, some financial institutions publicly announced that they would stop funding new thermal coal projects or would otherwise reduce their overall lending to coal producers. These or similar policies may adversely impact the coal industry generally, our ability to access capital and financial markets in the future, our costs of capital and the future global demand for coal.

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Our business may require substantial ongoing capital expenditures, and we may not have access to the capital required to reach full productive capacity at our mines.

Maintaining and expanding mines and related infrastructure is capital intensive. Specifically, the exploration, permitting and development of Met coal reserves, mining costs, the maintenance of machinery, facilities and equipment and compliance with applicable laws and regulations require ongoing capital expenditures. Any decision to increase production at our existing mines or to develop the high-quality Met coal recoverable reserves at our development properties in the future could also affect our capital needs or cause future capital expenditures to be higher than in the past and/or higher than our estimates. We cannot assure that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels and on our present levels or levels achieved prior to the COVID-19 pandemic and on our current or projected timelines, and we may be required to defer all or a portion of our capital expenditures. Our results of operations, business and financial condition may be materially adversely affected if we cannot make such capital expenditures.

To fund our capital expenditures, we will be required to use cash from our operations, incur debt or raise new equity. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings, on the other hand, 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. If cash flow generated by our operations or available borrowings under our bank financing arrangements are insufficient to meet our capital requirements and we are unable to access the capital markets on acceptable terms or at all, we could be forced to curtail the expansion of our existing mines and the development of our properties which, in turn, could lead to a decline in our production and could materially and adversely affect our business, financial condition and results of operations.

We may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets.

Our balance sheet includes a number of assets that are subject to impairment risk, particularly long-lived assets, including property, plant and equipment, mining tenements, exploration and evaluation assets and intangible assets (including goodwill). The values of these assets are generally derived from the fundamental valuation of the underlying mining operations and, as such, are subject to many of the same risks to which our operations are exposed, including decreases in coal prices, foreign currency exchange risks, operational and geological risks, changes in coal production and changes in estimates of proven and probable coal reserves. Adverse changes in these and other risk factors could lead to a reduction in the valuation of certain of our assets and result in an impairment charge being recognized.

In 2020, as a result of the ongoing COVID-19 pandemic and resulting market conditions, we recognized a non-cash impairment charge of $78.1 million in relation the Greenbrier mining asset in our financial results.

Risks related to our investment in WICET may adversely affect our financial condition and results of operations.

We have a minority interest in WICET Holdings Pty Ltd, whose wholly owned subsidiary, Wiggins Island Coal Export Terminal Pty Ltd , or WICET Pty Ltd, owns WICET. Other coal producers who export coal through WICET also hold shares in WICET Holdings Pty Ltd. In addition, we and the other coal producers (or shippers) have evergreen, ten year take-or-pay agreements with WICET Pty Ltd and pay a terminal handling charge to export coal through WICET, which is calculated by reference to WICET’s annual operating costs, as well as finance costs associated with WICET Pty Ltd’s external debt facilities.

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Under our take-or-pay agreement with WICET Pty Ltd, or the WICET Take-or-Pay Agreement, Curragh’s export capacity is 1.5 MMtpa and we are obligated to pay the terminal handling charge for this capacity, whether utilized or not. The terminal handling charge calculation is based on total operating and finance costs of WICET Pty Ltd being charged to contracted shippers in proportion to each shipper’s contracted capacity. Under the terms of the WICET Take-or-Pay Agreement the terminal handling charge payable by us can be adjusted (increased or decreased) by WICET Pty Ltd if WICET Pty Ltd’s operating and finance costs change, or if a contracted shipper defaults on its take-or-pay agreement obligations and has its contracted capacity reduced to nil. Under the terms of the WICET Take-or-Pay Agreement there is a limit of how much WICET Pty Ltd can charge us for recovery of its finance costs, referred to as a finance cap. Since WICET began operating in April 2015, four WICET Holdings Pty Ltd shipper-shareholders have defaulted on their obligations under their respective take-or-pay agreements and subsequently had those agreements terminated. The result of these terminations is a decrease in the aggregate contracted tonnage at WICET from 27 MMtpa to 15.5 MMtpa.

In addition, in July 2019, we were assigned export capacity of 1.6 Mtpa at WICET from another shipper on a take-or-pay basis for a term to June 30, 2022, at prevailing market rates. This assignment increases our total terminal handling charge costs for access to WICET. The terms under this take-or-pay arrangement differ from those in our original WICET Take-or-Pay Agreement. Under the terms and conditions of this take-or-pay arrangement, the other shipper has transferred their assigned capacity at the port and in exchange we will be paying a terminal handling charge that will reflect the operating cost. The finance cap or debt component of the terminal handling charge is still at the original shipper’s account.

Given the operation of the finance cap (which has been reached, subject to further adjustment for Consumer Price Index, or CPI) there is a limit to the recovery by WICET of its financing costs from shippers. Accordingly, prior defaults referred to above have resulted in only minor increases to the terminal handling charges payable by the remaining shipper shareholders (including us). These increases have related to higher A$/ton (or U$/ton) charge for operating costs resulting from a lower contract base. If any of the remaining shipper shareholders becomes insolvent and/or defaults under its take-or-pay agreement, the terminal handling charges for the remaining shipper shareholders, including us, may increase proportionately to pay the defaulting shipper’s share of WICET’s operating and financing costs going forward (noting that the finance cap applies in respect of the financing costs component of the terminal handling charges).

In addition, if we default under the WICET Take-or-Pay Agreement and that default is not remedied, then we will be obligated to pay a termination payment. The termination payment is equal to the lesser of our proportion of WICET Pty Ltd’s total external debt (which is based on the proportion that our contracted tonnage bears to the total contracted tonnage at WICET when the payment obligation is triggered) and ten years equivalent terminal handling charges at the prevailing rate at the time that the termination payment falls due. We have provided security to WICET Pty Ltd in the form of a bank guarantee, the amount of which is required to cover our estimated liabilities as a shipper under the WICET Take-or-Pay Agreement for the following twelve-month period.

In the event of WICET Pty Ltd defaulting on its external debt obligations, external lenders to WICET Pty Ltd may enforce their rights to the security over the assets of WICET and appoint a receiver to take steps to recover outstanding debt. The external lenders do not have direct recourse to the shippers to recover outstanding debt and shipper take-or-pay agreements would remain on foot and access to the port would continue to be available to us.

In the event of a permanent cessation of operations at WICET, we may be required to procure additional port capacity elsewhere, as well as be liable for a termination payment under our take-or-pay agreement.

Risks related to the Supply Deed with Stanwell may adversely affect our financial condition and results of operations.

Curragh has a CSA, as amended from time to time, with Stanwell to supply thermal coal to the Stanwell Power Station. The CSA restricted Curragh from mining the SRA which was reserved for the benefit of Stanwell and could not be mined without Stanwell’s consent. Under the CSA, in addition to supplying thermal coal at a price below the cost to Curragh of mining and processing the coal, Curragh pays certain rebates to Stanwell on Met coal exported from certain parts of Curragh, which represents the deferred purchase cost of the right to mine some areas at Curragh. Our cost of supplying coal to Stanwell has been and may continue to be greater than the price paid by Stanwell.

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On August 14, 2018, Curragh entered into the Supply Deed with Stanwell. The Supply Deed grants Curragh the right to mine the coal reserves in the SRA. In exchange for these rights, Curragh has agreed to certain amendments to the CSA and to enter into the NCSA, which will commence on or around the expiration of the CSA (currently expected to expire in 2027). On July 12, 2019, Curragh entered into the NCSA with Stanwell. Curragh agreed that the total value of the discount received by Stanwell on coal supplied to it under the NCSA should (by the expiry date of the NCSA) be equal to the net present value of A$210 million as at the date of the Supply Deed. No export rebates are payable during the term of the NCSA. The amortized cost of the deferred consideration was $230.5 million (A$317.7 million) as of December 31, 2021.

We could be adversely affected if we fail to appropriately provide financial assurances for our obligations.

Australian laws and U.S. federal and state laws require us to provide financial assurances related to requirements to reclaim lands used for mining, to pay federal and state workers’ compensation, to provide financial assurances for coal lease obligations and to satisfy other miscellaneous obligations. The primary methods we use to meet those obligations in the United States are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2021, we provided $29.6 million of third-party surety bonds in connection with our U.S. Operations. There are no cash collateral requirements to support any of the outstanding bonds.

Our financial assurance obligations may increase due to a number of factors, including the size of our mining footprint and new government regulations, and we may experience difficulty procuring or renewing our surety bonds. In addition, our bond issuers may demand higher fees or additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by federal and state law to have these bonds or other acceptable security in place before mining can commence or continue, any failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would adversely affect our ability to mine coal. That failure could result from a variety of factors, including lack of availability of surety bond or letters of credit, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and the requirement to provide collateral for future third-party surety bond issuers under the terms of financing arrangements. If we fail to maintain adequate bonding, our mining permits could be invalidated, which would prevent mining operations from continuing, and future operating results could be materially adversely affected.

In Australia, the Financial Provisioning Act amends the financial assurance provisions of the Environmental Protection Act 1994 (Qld), and impacts the way that our Australian Operations must provision for and manage associated costs of providing financial assurances related to mine rehabilitation obligations.

The Financial Provisioning Act:

•amends the financial assurance arrangements for resource activities under the Environmental Protection Act 1994 (Qld) with a new financial provisioning scheme, and changes how the ERC for an environmental authority is calculated; and

•amends the Environmental Protection Act 1994 (Qld) to introduce new requirements for the progressive rehabilitation and closure of mined land.

Since April 1, 2019, any financial assurance currently held for environmental approvals already held in Australia are treated as surety under the Financial Provisioning Act. There will be a transition period of three years that commenced in early 2019 during which all miners in Queensland were assessed and received an initial risk allocation decision based on a formulaic calculation of their ERC. Our ERC is the cost estimated by the government department of rehabilitating the land on which our operation is carried out. This allocation will put our resource activity at Curragh into a risk category under the Financial Provisioning Act based on the regulator’s assessment of both the amount of our ERC and our financial capacity to carry out and discharge the rehabilitation liability and obligation at the time our mining operations cease. This risk assessment is reviewed annually, and assessment fees are payable each time there is an allocation decision for our operations in Queensland.

The new financial provisioning scheme is managed by the Scheme Manager and financial assurance is provided by paying a contribution to the Scheme and/or the giving of surety to the Scheme Manager. Our contribution is calculated as the prescribed percentage (dependent on risk allocation decision) of Curragh’s ERC. The prescribed percentages for each category are: (1) Very low: 0.5%; (2) Low: 1.0%; and (3) Moderate: 2.75%. In the event Curragh’s ERC is allocated a high risk allocation, we will be required to negotiate the percentage of surety to be provided with the Scheme Manager. The Scheme Manager is a statutory officer and manages the Scheme contributions and the sureties on behalf of the Queensland State Government.

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In October 2021, the Scheme Manager completed the assessment of the Annual Review Allocation for environmental authority number EPML00643713 and issued an Annual Review Allocation of “Moderate”. The moderate rating results in Curragh being obliged to make a financial contribution to the Scheme of 2.75% of the ERC. In January 2022, the Scheme Manager completed an assessment of the Annual Review Allocation for Environmental Authority Number EPVX00635313 and issued an Annual Review Allocation of “High” in respect of MDL162 requiring Curragh to maintain its historical financial assurance in respect of 100% of the ERC for Environmental Authority Number EPVX00635313.

There can be no assurance that our risk category allocation will not change in future years.

Our financial assurance obligations may increase due to a number of factors, including but not limited to:

•any change that increases ERC or area of disturbance;

•any major Environmental Authority amendment;

•compliance with existing Environmental Authority obligations; and

•major changes to financial soundness of the EA Holder.

For more information on the Financial Provisioning Act, see Item 1. “Business—Regulatory Matters—Australia—Environmental Protection Act 1994 (Qld).”

Mine closures entail substantial costs. If we prematurely close one or more of our mines, our operations and financial performance would likely be affected adversely.

Federal and state regulatory agencies have the authority following significant health and safety incidents, such as fatalities, to order mining operations to be temporarily suspended or a facility be permanently closed. For example, on January 12, 2020, operations at our Curragh mine were temporarily suspended after a contractor was fatally injured during a tire change activity in the main workshop on site and on November 21, 2021, operations at our Curragh mine were temporarily suspended after an employee was fatally injured while working in the dragline operations. We could also be required to close or discontinue operations at particular mines before the end of their mine life due to environmental, geological, geotechnical, commercial, leasing or other issues. Such closure or discontinuance of operations could result in significant closure and rehabilitation expenses, employee redundancy costs, contractor demobilization costs and other costs or loss of revenues. If and when incurred, these closure and rehabilitation costs could exceed our current estimates. If one or more of our mines is closed earlier than anticipated, we would be required to fund the reclamation and closure costs on an expedited basis and potentially lose revenues and, for some of our operations, pay for take-or-pay arrangements that we no longer use, which would have an adverse impact on our operating and financial performance. Many of these costs could also be incurred if a mine was unexpectedly placed on care and maintenance before the end of its planned mine life such as our mines in the U.S. Operations, which were temporarily idled in 2020 as a result of the ongoing COVID-19 pandemic.

If the assumptions underlying our provision for reclamation and mine closure obligations prove to be inaccurate, we could be required to expend greater amounts than anticipated.

The Environmental Protection Act 1994 (Qld) and the SMCRA establish operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities totaled $120.3 million as of December 31, 2021, based upon permit requirements and the historical experience at our operations, and depend on a number of variables involving assumptions and estimation and therefore may be subject to change, including the estimated future asset retirement costs and the timing of such costs, estimated proven reserves, assumptions involving third-party contractors, inflation rates and discount rates. If these accruals are insufficient or our liability in a future year is greater than currently anticipated, our future operating results and financial position could be adversely affected. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates.”

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We are subject to foreign exchange risks involving certain operations in multiple countries.

Loss sustained from adverse movements in currency exchange rates can impact our financial performance and financial position and the level of additional funding required to support our businesses. Our financial results are reported in US$ and certain parts of our liabilities, earnings and cash flows are influenced by movements in exchange rates, especially movements in A$ to US$ exchange rate. For example, costs relating to our Australian Operations are generally denominated in A$. In addition, foreign currency exposures arise in relation to coal supply contracts, procurement of plant and equipment and debt, which may be priced in A$ or other foreign currencies other than US$.

The impact of currency exchange rate movements will vary depending on factors such as the nature, magnitude and duration of the movements, the extent to which currency risk is hedged under forward exchange contracts or other hedging instruments and the terms of these contracts. We may enter into forward exchange contracts to hedge a portion of our foreign currency exposure of our Australian Operations from time to time. The unhedged portion of our non-US$ exposures against exchange rate fluctuations will be at the risk of any adverse movement in exchange rates, which may affect our operating results, cash flows and financial condition.

Interest rates could change substantially and have an adverse effect on our profitability.

We are exposed to interest rate risk in relation to variable-rate bank balances and variable-rate borrowings. Our interest rate risk primarily arises from fluctuations in LIBOR and the Australian Bank Bill Swap Yield, or BBSY, in relation to US$- and A$-denominated borrowings, respectively. Our lending rates may increase in the future as a result of factors beyond our control and may result in an adverse effect on our financial condition and results of operations.

In addition, national and international regulators and law enforcement agencies have conducted investigations into a number of rates or indices, which are deemed to be “reference rates.” Actions by such regulators and law enforcement agencies may result in changes to the manner in which certain reference rates are determined, their discontinuance, or the establishment of alternative reference rates. For example, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, has announced that it will no longer compel banks to submit rates for the calculation of non-U.S.-dollar LIBOR after 2021. U.S-dollar LIBOR must be replaced before June 30, 2023. The Alternative Reference Rates Committee has proposed SOFR as its recommended alternative to LIBOR. At this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates, including SOFR, may have on LIBOR or other benchmarks, including LIBOR-based borrowings under our variable-rate bank balances and variable-rate borrowings. Furthermore, the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our benchmark-based borrowings to be materially different than expected and could materially adversely impact our ability to refinance such borrowings or raise future indebtedness on a cost effective basis.

We may be unsuccessful in integrating the operations of acquisitions 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. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including the following:

•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 diversion of management’s attention from other operations; and

•timing, and whether the acquisition or business expansion is occurring during adverse economic, social and regulatory periods.

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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.

Coronado Global Resources Inc. is a holding company with no operations of its own and, as such, it depends on its subsidiaries for cash to fund its operations and expenses, including future dividend payments, if any.

As a holding company, our principal source of cash flow is distributions from our subsidiaries. Therefore, our ability to fund and conduct our business, service our debt, and pay dividends, if any, in the future will depend on the ability of our subsidiaries to generate sufficient cash flow to make upstream cash distributions to us. Our subsidiaries are separate legal entities, and although they are wholly-owned and controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends, or otherwise. The ability of our subsidiaries to distribute cash to us will also be subject to, among other things, restrictions that may be contained in our subsidiary agreements (as entered into from time to time), availability of sufficient funds in such subsidiaries and applicable laws and regulatory restrictions. Claims of any creditors of our subsidiaries generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability of our subsidiaries to distribute dividends or other payments to us is limited in any way, our ability to fund and conduct our business, service our debt, and pay dividends, if any, could be harmed.

Legal, Compliance and Sustainability Risks

We are subject to extensive health and safety laws and regulations that could have a material adverse effect on our reputation and financial condition and results of operations.

We are subject to extensive laws and regulations governing health and safety at coal mines in the United States and Australia. As a result of increased stakeholder focus on health and safety issues (such as black lung disease or coal workers’ pneumoconiosis), there is a risk of legislation and regulatory change that may increase our exposure to claims arising out of current or former activities or result in increased compliance costs (e.g., through requiring improved monitoring standards or contribution to an industry-pooled fund). Regulatory agencies also have the authority, following significant health and safety incidents, such as fatalities, to order mining operations to be temporarily suspended or the facility be permanently closed. For example, For example, on January 12, 2020, operations at our Curragh mine were temporarily suspended after a contractor was fatally injured during a tire change activity in the main workshop on site and on November 21, 2021, operations at our Curragh mine were temporarily suspended after an employee was fatally injured while working in the dragline operations.. If further serious safety incidents were to occur at any of our mining facilities in the future, it is possible that a regulator might impose a range of conditions on re-opening of a facility, including requiring capital expenditures, which could have an adverse effect on our reputation, financial condition and results of operations.

For additional information about the various regulations affecting us, see Item 1. “Business—Regulatory Matters—Australia” and “Business—Regulatory Matters—United States.”

We could be negatively affected if we fail to maintain satisfactory labor relations.

Relations with our employees and, where applicable, organized labor are important to our success. Enterprise bargaining and other disputes between us and our employees or disputes affecting our contractors may result in strikes or uncompetitive work practices.

As of December 31, 2021, we had 1,577 employees. In addition, as of December 31, 2021, there were 1,848 contractors supplementing the permanent workforce, primarily at Curragh. As of December 31, 2021, approximately 12% of our total employees, all at our Australian Operations, were represented by organized labor unions and covered by the EA. In May 2019, the Australian Fair Work Commission approved the Curragh Mine Enterprise Agreement 2019. This EA has a nominal expiration date of May 26, 2022 and will remain in place until replaced or terminated by the Fair Work Commission. Our U.S. Operations employ a 100% non-union labor force.

Future industrial action by our employees or mining contractors’ employees or involving trade unions could disrupt operations and negatively impact mine productivity, production and profitability.

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Our operations may impact the environment or cause exposure to hazardous substances, which could result in material liabilities to us.

We are subject to extensive environmental laws and regulations, and our operations may substantially impact the environment or cause exposure to hazardous materials to our contractors, our employees or local communities. We use hazardous materials and generate hazardous or other regulated waste, which we store in our storage or disposal facilities. We may become subject to statutory or common law claims (including damages claims) as a result of our use of hazardous materials and generation of hazardous waste. A number of laws, including, in the United States, the CERCLA or Superfund, and the RCRA, and in Australia, the Environmental Protection Act 1994 (Qld), impose liability relating to contamination by hazardous substances. Furthermore, the use of hazardous materials and generation of hazardous and other waste may subject us to investigation and require the clean-up of soil, surface water, groundwater and other media.

Mining operation process, including blasting and processing ore bodies, can also generate environmental impacts. These impacts include, but are not limited to, leakages of polluting substances, explosions, flooding, fires, accidental mine water discharges, and excessive dust and noise. Such risks could result in damage to the applicable mine site, personal injury to our employees and contractors, environmental damage, decreased coal production and possible legal liability under environmental regulations. Employee or strict liability claims under common law or environmental regulations in relation to these matters may arise, for example, out of current or former activities at sites that we own, lease or operate and at properties to which hazardous substances have been sent for treatment, storage, disposal or other handling. Our liability for such claims may be strict, joint and several with other miners or parties or with our contractors, such that we may be held responsible for more than our share of the contamination or other damages, or even for the entire amount of damages assessed. Additionally, any violations of environmental laws by us could lead to, among other things, the imposition on us of substantial fines, penalties, other civil and criminal sanctions, the curtailment or cessation of operations, orders to pay compensation, orders to remedy the effects of violations and take preventative steps against possible future violations, increased compliance costs, or costs for environmental remediation, rehabilitation or rectification works.

We maintain extensive Met coal refuse areas and slurry impoundments at our mining properties. At Curragh, coal slurry is disposed of by pumping into an impoundment area where particles are allowed to settle. We have procedures in place that the Curragh slurry impoundments remain below the surrounding topography so that there is minimal likelihood of failure and/or spills. At our U.S. Operations, refuse areas and impoundments are frequently inspected and subject to extensive governmental regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as create liability for related personal injuries, property damages and injuries to natural resources and plant and wildlife. Of the six refuse areas among our U.S. mining properties, only three impound slurry; the other facilities are combined refuse and do not impound slurry. Four of our impoundments in the U.S. overlie mined out areas, which can pose a heightened risk of failure and the assessment of damages arising out of such failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for related fines and penalties.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion and coal mining in many jurisdictions, which could significantly affect demand for our products or our securities.

Global concerns about climate change continues to attract considerable attention, particularly in relation to the coal industry. Emissions from coal consumption, both directly and indirectly, and emissions from coal mining itself are subject to pending and proposed regulation as part of initiatives to address global climate change. A number of countries, including Australia and the United States, have already introduced, or are contemplating the introduction of, regulatory responses to GHGs, including the extraction and combustion of fossil fuels, to address the impacts of climate change.

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There are three primary sources of GHGs associated with the coal industry. First, the end use of our coal by our customers in coal-fired electricity generation, coke plants, and steelmaking. Second, combustion of fuel by equipment used in coal production and to transport our coal to our customers. Third, coal mining itself can release methane, which is considered to be a more potent GHG than carbon dioxide, directly into the atmosphere. These emissions from coal consumption, transportation and production are subject to pending and proposed regulation, in the jurisdictions in which we operate as part of initiatives to address global climate change.

As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. In November 2014, an agreement was announced between the United States and China to cut GHGs by more than 25% below 2005 levels by 2025. This agreement was followed by the UNFCCC, conference in Paris, France, in which an agreement was adopted calling for voluntary emissions reductions contributions, or the Paris Agreement. The Paris Agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, which account for at least 55% of global GHG emissions. The Paris Agreement was signed by representatives from 195 countries and aims to hold back the increase in global temperatures, increase the ability of countries to adapt to the adverse impacts of climate change and provide channels to finance projects that lead to GHG reductions.

On November 13, 2021, the Glasgow Conference of Parties 26, or COP26, agreed on the language around fossil fuels in the final Glasgow Climate Pact. A call on countries to “phase out” coal power was changed to “phase down of unabated coal power”, that is coal power that does not include the capture and storage of carbon dioxide emission. 190 countries have now agreed to phase down coal power. 65 countries have now committed to coal phase out, including more than 20 new commitments at COP26. 48 countries are members of the PPCA. All major coal financing countries have committed to end international coal finance by the end of 2021. As a result, Glasgow COP26 is expected to accelerate the trend of higher finance and insurance costs for coal miners and coal-fired power generators. The agreement on carbon accounting has also made global trade in carbon more likely, eventually accelerating the competitiveness of low-carbon solutions in the power and steel sectors.

In addition, the growth of alternative energy options, such as renewables and disruptive power generation technologies, changes in community or government attitudes to climate change, government measures to subsidize renewable energy production while reducing subsidies for the fossil fuel industry, efforts to promote divestment of fossil fuel equities and pressure from lenders to limit funding to fossil fuel companies could result in further development of alternative energy industries and broader mainstream acceptance of alternative energy options which could result in a material reduction in the demand for coal. It could also result in reduced access to capital to fund our activities as lenders and investors divert capital to low emission sectors of the economy.

The absence of regulatory certainty, global policy inconsistencies and direct regulatory impacts (such as carbon taxes or other charges) each have the potential to adversely affect our operations—either directly or indirectly, through suppliers and customers. Collectively, these initiatives and developments could result in higher electricity costs to us or our customers or lower the demand for coal used in electricity generation, which could in turn adversely impact our business.

At present, we are principally focused on Met coal production, which is not used in connection with the production of coal-fired electricity generation. The market for our coal may be adversely impacted if comprehensive legislation or regulations focusing on GHG emission reductions are adopted, particularly if they directly or indirectly impact the Met coal industry, or if our ability to obtain capital for operations is materially reduced.

We and our customers may also have to invest in carbon, capture, usage and storage technologies in order to burn thermal coal and comply with future GHG emission standards. The potential direct and indirect financial impact on us of future laws, regulations, policies and technology developments may depend upon the degree to which any such laws, regulations and developments force reduced reliance on coal as a fuel source. Such developments could result in adverse impacts on our financial condition or results of operations. See Item 1. “Business—Regulatory Matters—Australia” and “Business—Regulatory Matters—United States.”

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Changes in and compliance with government policy, regulation or legislation may adversely affect our financial condition and results of operations.

The coal mining industry is subject to regulation by federal, state and local authorities in each relevant jurisdiction with respect to a range of industry specific and general matters. Any future legislation and regulatory change imposing more constraints or more stringent requirements may affect the coal mining industry and may adversely affect our financial condition and results of operations. Examples of such changes are, future laws or regulations that may limit the emission of GHGs or the use of thermal coal in power generation, more stringent workplace health and safety laws, more rigorous environmental laws, and changes to existing taxation and royalty legislation.

Compliance with applicable federal, state and local laws and regulations may become more costly and time-consuming and may delay commencement or interrupt continuation of exploration or production at our operations. We have incurred, and may in the future incur, significant expenditures to comply with such regulation and legislation. These laws are constantly evolving and may become increasingly stringent. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that certain implementation of the regulations for these laws have not yet been promulgated and in certain instances are undergoing revision. These laws and regulations, particularly new legislative or administrative proposals (or judicial interpretations of existing laws and regulations), could result in substantially increased capital, operating and compliance costs and could have a material adverse effect on our operations and our customers’ ability to use our products. Due in part to the extensive and comprehensive regulatory requirements, along with changing interpretations of these requirements, violations of applicable federal, state and local laws and regulations occur from time to time in the coal industry and minor violations have occurred at our Australian Operations and our U.S. Operations in the past.

Moreover, changes in the law may impose additional standards and a heightened degree of responsibility for us and our stockholders, directors and employees; may require unprecedented compliance efforts; could divert our management’s attention; and may require significant expenditures. For example, we may also be subject to unforeseen environmental liabilities resulting from coal-related activities, which may be costly to remedy or adversely impact our operations. In particular, the acceptable level of pollution and the potential abandonment costs and obligations for which we may become liable as a result of our activities may be difficult to assess under the current legal framework. To the extent that required expenditures, as with all costs, are not ultimately reflected in the prices of coal, our operating results will be detrimentally impacted. The costs and operating restrictions necessary for compliance with safety and environmental laws and regulations, which is a major cost consideration for our Australian Operations and U.S. Operations, may have an adverse effect on our competitive position relative to foreign producers and operators in other countries which may not be required to incur equivalent costs in their operations.

We are also affected by various other international, federal, state, local and tribal or indigenous environmental laws and regulations that impact our customers. To the extent that such environmental laws and regulations reduce customer demand for or increase the price of coal, we will be detrimentally impacted. For additional information about the various regulations affecting us, see Item 1. “Business—Regulatory Matters—Australia” and “Business—Regulatory Matters—United States.”

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Failure to comply with applicable anti-corruption and trade laws, regulations and policies could result in fines and criminal penalties, causing a material adverse effect on our business, operating and financial prospects or performance.

Any fraud, bribery, misrepresentation, money laundering, violations of applicable trade sanctions, anti-competitive behavior or other misconduct by our employees, contractors, customers, service providers, business partners and other third parties could result in violations of relevant laws and regulations by us and subject us or relevant individuals to corresponding regulatory sanctions or other claims, and could also result in an event of default under our financing arrangements. These unlawful activities and other misconduct may have occurred in the past and may occur in the future and may result in civil and criminal liability under increasingly stringent laws relating to fraud, bribery, sanctions, competition and misconduct or cause serious reputational or financial harm to us. In addition, failure to comply with environmental, health or safety laws and regulations, privacy laws and regulations, U.S. trade sanctions, the U.S. Foreign Corrupt Practices Act and other applicable laws or regulations could result in litigation, the assessment of damages, the imposition of penalties, suspension of production or distribution, costly changes to equipment or processes due to required corrective action, or a cessation or interruption of operations.

We have policies and procedures to identify, manage and mitigate legal risks and address regulatory requirements and other compliance obligations. However, there can be no assurance that such policies, procedures and established internal controls will adequately protect us against fraudulent or corrupt activity and such activity could have an adverse effect on our reputation, financial condition and results of operations.

We are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively.

Federal, state or local governmental authorities in nearly all countries across the global coal mining industry impose various forms of taxation on coal producers, including production taxes, sales-related taxes, royalties, stamp duty, environmental taxes and income taxes.

Included within acquisition related accruals in our Consolidated Balance Sheet, included in this Annual Report on Form 10-K, is an amount outstanding for stamp duty payable on the Curragh Acquisition of $31.2 million (A$ 43.0 million). This amount was outstanding as at December 31, 2021 and December 31, 2020, respectively, pending assessment by the Queensland Revenue Office, or QRO, in Queensland, Australia. The QRO has not yet provided any formal assessment of the stamp duty amount, although it has indicated that in its view, stamp duty may be assessed on the Curragh Acquisition, unencumbered by the Stanwell arrangements. As a result, the assessment of the stamp duty payable could potentially be higher than the amount provided for. The Company considers its position at December 31, 2021, as accounted for, is appropriate and the Company will vigorously challenge any assessment on the above basis.

If new legislation or regulations related to various forms of coal taxation or income or other taxes generally, which increase our costs or limit our ability to compete in the areas in which we sell coal, or which adversely affect our key customers, are adopted, or if the basis upon which such duties or taxes are assessed or levied, changes or is different from that provided by us, our business, financial condition or results of operations could be adversely affected.

We may be subject to litigation, the disposition of which could negatively affect our profitability and cash flow in a particular period, or have a material adverse effect on our business, financial condition and results of operations.

Our profitability or cash flow in a particular period could be affected by an adverse ruling in any litigation that may be filed against us in the future. In addition, such litigation could have a material adverse effect on our business, financial condition and results of operations. See Item 3. “Legal Proceedings.”

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We have no registered trademarks for our Company name or other marks used by us in the United States or any other countries, and failure to obtain those registrations could adversely affect our business.

Although we have filed a trademark application for use of the stylized mark “CORONADO STEEL STARTS HERE” in the United States and Australia, our applications are still pending and the corresponding mark has not been registered in the United States or Australia. We have not filed for this or other trademarks in any other country. During trademark registration proceedings, we may receive rejections. If so, we will have an opportunity to respond, but we may be unable to overcome such rejections. In addition, Intellectual Property Australia and the United States Patent and Trademark Office and comparable agencies in many foreign jurisdictions may permit third parties to oppose pending trademark applications and to seek to cancel registered trademarks. If opposition or cancellation proceedings are filed against our trademark application, our trademark may not survive such proceedings, and/or we may be required to expend significant additional resources in an effort to defend ourselves in the proceedings or identify a suitable substitute mark for future use.

Risks Specific to Our Common Stock

Our certificate of incorporation and bylaws include provisions that may discourage a change in control.

Provisions contained in our amended and restated certificate of incorporation, or certificate of incorporation, and amended and restated bylaws, or bylaws, and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions.

We have elected not to be governed by Section 203 of the General Corporation Law of the State of Delaware, or the DGCL, (or any successor provision thereto), until immediately following the time at which the EMG Group no longer beneficially owns in the aggregate shares of our common stock representing at least 10% of our voting stock, in which case we shall thereafter be governed by Section 203 if and for so long as Section 203 by its terms would apply to us. Section 203 provides that an interested stockholder, along with its affiliates and associates (i.e., a stockholder that has purchased greater than 15%, but less than 85%, of a company’s outstanding voting stock (with some exclusions)), may not engage in a business combination transaction with the company for a period of three years after buying more than 15% of a company’s outstanding voting stock unless certain criteria are met or certain other corporate actions are taken by the company.

These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.

Our certificate of incorporation limits the personal liability of our directors for certain breaches of fiduciary duty.

Our certificate of incorporation and bylaws include provisions limiting the personal liability of our directors for breaches of fiduciary duty under the DGCL. Specifically, our certificate of incorporation contains provisions limiting a director’s personal liability to us and our stockholders to the fullest extent permitted by the DGCL. Furthermore, our certificate of incorporation provides that no director shall be liable to us and our stockholders for monetary damages resulting from a breach of fiduciary duty as a director, except to the extent that such exemption from liability or limitation thereof is not permitted under the DGCL. The principal effect of this limitation on liability is that a stockholder will be unable to prosecute an action for monetary damages against a director unless the stockholder can demonstrate a basis for liability that cannot be eliminated under the DGCL. These provisions, however, should not limit or eliminate our right or any stockholder’s right to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s fiduciary duty. These provisions do not alter a director’s liability under U.S. federal securities laws. The inclusion of these provisions in our certificate of incorporation may discourage or deter stockholders or management from bringing a lawsuit against directors for a breach of their fiduciary duties, even though such an action, if successful, might otherwise have benefited us and our stockholders.

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Coronado Group LLC and the EMG Group have substantial control over us and are able to influence corporate matters.

Coronado Group LLC and the EMG Group have significant influence over us, including control over decisions that require the approval of stockholders, which could limit the ability of other stockholders to influence the outcome of stockholders votes.

As of December 31, 2021, the EMG Group indirectly held 50.4% of our outstanding shares of common stock. Therefore, the EMG Group has effective control over the outcome of votes on all matters requiring approval by stockholders. There is a risk that the interests of the EMG Group could conflict with or differ from our interests or the interests of other stockholders. In addition, pursuant to the terms of the Stockholder’s Agreement, dated as of September 24, 2018, between us and Coronado Group LLC, or the Stockholder’s Agreement, so long as it beneficially owns in the aggregate at least 25% of the outstanding shares of our common stock, the EMG Group will have the ability to exercise substantial control over certain of our transactions, including change of control transactions, such as mergers and capital and debt raising transactions. See Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for a description of the Stockholder’s Agreement.

Further, pursuant to the terms of the Series A Share, Coronado Group and the EMG Group or its successors or permitted assigns, as the beneficial owner of the Series A Share, at its option, will have the ability to elect a specified number of directors, or the Series A Directors, based on the EMG Group’s aggregate level of beneficial ownership of shares of our common stock. For more details on the ability of Coronado Group and the EMG Group to elect Series A Directors, as well as the rights of stockholders to participate in the removal of any such Series A Directors, see Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”

Moreover, the EMG Group’s beneficial ownership of shares of our common stock may also adversely affect the price of our common stock to the extent equity investors perceive disadvantages in owning common stock of a company with a controlling stockholder. In addition, the EMG Group is in the business of making investments in companies and may, from time to time, acquire interests in businesses that directly or indirectly compete with us, as well as businesses of our existing or potential significant customers. The EMG Group may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue, and as a result, the interests of the EMG Group may not align with the interests of our other stockholders.

The EMG Group has the right, subject to certain conditions, to require us to cooperate in a sale of shares of our common stock held by it (including in the form of CDIs) under the Securities Act.

Pursuant to the Registration Rights and Sell-Down Agreement, dated as of September 24, 2018, between us and Coronado Group LLC, or the Registration Rights and Sell-Down Agreement, Coronado Group LLC (or its successors or permitted assigns or transferees) has the right, subject to certain conditions, to require us to cooperate in a sell-down of shares of our common stock or CDIs held by it. By virtue of its majority ownership, exercising its registration rights and selling a large number of shares or CDIs, Coronado Group LLC could cause undue volatility in the prevailing market price of our common stock. See Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”

Our non-employee directors and their respective affiliates, including the EMG Group, may be able to take advantage of a corporate opportunity that would otherwise be available to us.

The corporate opportunity and related party transactions provisions in our certificate of incorporation could enable any of our non-employee directors or their respective affiliates, including the EMG Group, to benefit from corporate opportunities that might otherwise be available to us. Subject to the limitations of applicable law, our certificate of incorporation, among other things, will:

•permit us to enter into transactions with entities in which one or more non-employee directors are financially or otherwise interested;

•permit any non-employee director or his or her affiliates to conduct a business that competes with us and to make investments in any kind of property in which we may make investments; and

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•provide that if any non-employee director becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that non-employee director solely in his or her capacity as our director), that non-employee director will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to his or her affiliates and pursue or acquire such opportunity for himself or herself, and that non-executive director will not be deemed to have acted in a manner inconsistent with his or her fiduciary or other duties to us or our stockholders regarding the opportunity or acted in bad faith or in a manner inconsistent with our and our stockholders’ best interests.

These provisions enable a corporate opportunity that would otherwise be available to us to be taken by or used for the benefit of the non-employee directors or their respective affiliates, which include the EMG Group as a result of the rights granted to it under the Stockholder’s Agreement.

General Risk Factors

Any failure to maintain effective internal control over financial reporting may adversely affect our financial condition and results of operations.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States, or U.S. GAAP.

During the course of the preparation of our financial statements, we evaluate and correct any deficiencies in our internal controls over financial reporting. If we fail to maintain an effective system of disclosure or internal controls over financial reporting, including satisfaction of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002, we may not be able to report accurately or timely on our financial results or adequately identify and reduce fraud. Therefore, 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 CDIs, and we could be exposed to litigation or regulatory proceedings, which may be costly or divert management attention.

The requirements of being a public company in the United States and Australia may strain our resources, divert management’s attention, and affect our ability to attract and retain executive management and qualified board members.

Our CDIs are currently listed on the ASX and we are registered as a foreign company in Australia. As such we need to ensure continuous compliance with relevant Australian laws and regulations, including the listing rules of the ASX, as amended from time to time, or the ASX Listing Rules, and certain provisions of the Corporations Act 2001 (Cth), or the Corporations Act.

As a U.S. public company, we are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act of 2002, the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and other applicable securities laws, rules and regulations. Compliance with these laws, rules, and regulations may increase our legal and financial compliance costs, make some activities more difficult, time-consuming, or costly, and increase demand on our systems and resources. The Exchange Act requires, among other things, that we file annual, quarterly, and current reports with respect to our business and results of operations. In the absence of a waiver from the ASX Listing Rules, these SEC periodic reports will be in addition to our periodic filings required by the ASX Listing Rules. The Sarbanes-Oxley Act of 2002 requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting. In order to maintain and, if required, improve our disclosure controls and procedures and internal control over financial reporting to meet this standard, significant resources and management oversight will be required. As a result, management’s attention may be diverted from other business concerns and our costs and expenses will increase, which could harm our business and results of operations, all of which could be magnified during the ongoing COVID-19 pandemic. We may need to hire more employees in the future or engage outside consultants, which will increase our costs and expenses.

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In addition, changing laws, regulations, and standards relating to corporate governance and public disclosure are creating uncertainty for public companies, increasing legal and financial compliance costs and making some activities more time consuming. These laws, regulations and standards are subject to varying interpretations, in many cases due to their lack of specificity and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from sales-generating activities to compliance activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing bodies due to ambiguities related to their application and practice, regulatory authorities may initiate legal, administrative or other proceedings against us and our business may be harmed.

A state court located within the State of Delaware (or, if no state court located within the State of Delaware has jurisdiction, the federal district court for the District of Delaware) will be, to the extent permitted by law, the sole and exclusive forum for substantially all state law based disputes between us and stockholders.

Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, a state or federal court within the State of Delaware will be the sole and exclusive forum for:

•any derivative action or proceeding brought on our behalf;

•any action or proceeding asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee or agent of the Company to the Company or the Company’s stockholders or debtholders;

•any action or proceeding asserting a claim against the Company or any director or officer or other employee or agent of the Company arising pursuant to any provision of the DGCL or our certificate of incorporation or bylaws; or

•any action asserting a claim against the Company or any director or officer or other employee of the Company governed by the internal affairs doctrine or other “internal corporate claims” as defined in Section 115 of the DGCL.

The choice of forum provision may limit a stockholder’s ability to bring a claim against us or our directors, officers, employees or agents in a forum that it finds favorable, which may discourage stockholders from bringing such claims at all. Alternatively, if a court were to find the choice of forum provision contained in our bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in another forum, which could materially adversely affect our business, financial condition and results of operations. However, the choice of forum provision does not apply to any actions arising under the Securities Act or the Exchange Act.

The issuance of additional common stock or securities convertible into our common stock could result in dilution of the ownership interest in us held by existing stockholders.

We may issue more CDIs in the future in order to fund future investments, acquisitions, capital raising transactions or to reduce our debt. While we will be subject to the constraints of the ASX Listing Rules regarding the percentage of our capital that we are able to issue within a 12-month period (subject to applicable exceptions), any such equity raisings may dilute the ownership of existing common stockholders.

We are subject to general market risks that are inherent to companies with publicly-traded securities and the price of our securities may be volatile.

We are subject to the general market risks that are inherent in all securities traded on a securities exchange. This may result in fluctuations in the trading price of our securities that are not explained by our fundamental operations and activities. There is no guarantee that the price of our securities will increase in the future, even if our earnings increase.

Our securities may trade at, above or below the price paid by an investor for those securities due to a number of factors, including, among others:

•general market conditions, including investor sentiment;

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•movements in interest and exchange rates;

•fluctuations in the local and global market for listed stocks;

•actual or anticipated fluctuations in our interim and annual results and those of other public companies in our industry;

•industry cycles and trends;

•mergers and strategic alliances in the coal industry;

•changes in government regulation;

•potential or actual military conflicts or acts of terrorism;

•changes in accounting principles;

•announcements concerning us or our competitors;

•changes in government policy, legislation or regulation;

•inclusion of our securities in or removal from particular market indices (including S&P/ASX indices); and

•the nature of the markets in which we operate.

Other factors that may negatively affect investor sentiment and influence us, specifically, or the stock market, more generally, include acts of terrorism, an outbreak of international hostilities, fires, floods, earthquakes, labor strikes, civil wars, natural disasters, outbreaks of disease, such as the ongoing COVID-19 pandemic, or other man-made or natural events.

Stock markets have experienced extreme price and volume fluctuations in the past that are often disproportionate or unrelated to the operating performance of companies. There can be no guarantee that trading prices and volumes of any securities will be sustained. These factors may materially affect the market price of our securities, regardless of our operational performance. This may then significantly impact our ability to raise new equity which may be required to fund our operations if our financial performance deteriorates due to other factors.

The payment of dividends and repurchases of our stock are dependent on a number of factors, and future payments and repurchases cannot be assured.

The payment of dividends in respect of our common stock is impacted by several factors, including our profitability, retained earnings, capital requirements and free cash flow, as well as applicable covenants under the indenture governing our senior secured notes and covenants under the ABL Facility. Any future dividends will be determined by our Board of Directors having regard to these factors, among others. There is no guarantee that any dividend will be paid, or repurchases will be made, by us, or if paid, paid at historic levels. From time to time, our Board of Directors may also cancel previously announced dividends.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Summary Overview of Mining Operations

Coronado owns and controls a portfolio of operating mines and development projects in Queensland, Australia, and Virginia, West Virginia and Pennsylvania in the United States. Our Australian Operations consist of the 100%-owned Curragh producing mine complex. With respect to our U.S. Operations, Coronado owns a 100% interest in two producing mine complexes (Buchanan and Logan) and a 100% interest in one temporarily idled, production-stage mine complex (Greenbrier) and two development properties (Mon Valley (formerly called Pangburn-Shaner-Fallowfield) and Russell County). Figures 1 and 2 below show the locations of our mining properties in Australia and the United States, respectively.

Figure 1: Australian Operations:

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Figure 2: U.S. Operations:

For the years ended December 31, 2019, 2020 and 2021, our mines produced an aggregate of 20.2 MMt, 17.0 MMt and 17.4 MMt of coal, respectively. See the descriptions of our material mining properties under “—Curragh,” “—Buchanan,” “—Logan” and “—Mon Valley” below for more information. Table 1 below contains a summary of the key information relative to the various Coronado properties. Tables 2 and 3 provide a summary of our coal resources and reserves, respectively, as of December 31, 2021.

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Table 1. Summary Coronado Properties

(1) We are not aware of any significant encumbrances or defects in title with respect to any of our mining properties. Certain credit facilities of the Company are secured by a lien on substantially all of the Company’s assets, including mining properties.

(2) We believe we have secured all applicable environmental licenses and permits under applicable law and have all necessary permits and licenses regarding cultural heritage, native title and various other social issues to support current mining operations.

(3) Subject to the exercise of our renewal rights thereunder, most of the leases at our U.S. mining properties expire upon exhaustion of the relevant reserves.

(4) Proposed mine type.

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Table 2. Summary Coal Resources Exclusive of Reserves at End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1) For more information regarding price assumptions used in the calculation of coal resources as of December 31, 2021, see the individual property disclosures below.

(2) Australian resources are estimated inclusive of 5.3% in-situ moisture. United States resources are estimated on a dry basis.

Table 3. Summary Coal Reserves (Marketable Sales Basis) at End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1) For more information regarding price assumptions used in the calculation of coal reserves as of December 31, 2021, see the individual property disclosures below.

(2) For more information regarding moisture assumptions used in the calculation of coal reserves as of December 31, 2021, see the individual property disclosures below.

Curragh

Curragh is a production-stage mining property that consists of two active, open-pit, surface mines (Curragh North and Curragh Main). Coal mine development at the Curragh property is presently accomplished by surface mining methods and has been so historically since the mine’s inception. Curragh coals are widely known for their low ash, low to mid volatile matter, low sulfur and low phosphorous content. Curragh Met coal products are also known for their consistent delivered quality, which supports a consistent offtake across a diversified market base. A map of Curragh is shown in Figure 3.

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Figure 3. Coronado Curragh Mine Complex Property Location Map.

The Curragh mine complex is located within the Bowen Basin coalfields, approximately 200 kilometers by road west of Rockhampton, Queensland, Australia, and approximately 14 kilometers north of the town of Blackwater, Queensland, Australia. The coordinates of CPP1, which is located within Curragh Main, are 688,561 meters East, 7,400,933 meters North in the AMG66 grid system. Curragh owns and operates the necessary CPPs and load-out system for dispatches via Blackwater rail line to the Port of Gladstone or the Stanwell Power Station. See Item 1. “Business—Transportation—Australian Operations” for additional information regarding the rail and port services available to Curragh. Curragh also has maintenance facilities for the fleet of mining equipment, as well as office buildings for the mine staff and personnel. Established sealed roads connect the mine to the town of Emerald, Queensland, Australia, to the west and the Port of Gladstone to the east. Third-party rail providers operate the Blackwater rail line and transport Curragh export coal, for sale to international customers, to the RG Tanna Coal Terminal or Wiggins Island Coal Export Terminal at the Port of Gladstone. Curragh domestic coal is loaded onto train wagons for transportation to the Stanwell Power Station for power generation.

Curragh has ready access to water, electricity and personnel to support its operations. SunWater Ltd. supplies water to the mine complex from the Fairbairn Dam via the Bedford Weir. The mine complex also recycles water from on-site dams—i.e., old open-cut pits that capture rainfall and water from dewatering activities. Curragh has a dedicated 66-kilovolt, or kV, power supply to support the mining operations with a capacity of up to 57-megawatt, or MW, sourced from the main grid power. The substation is located on the southwest corner of ML1878 with both 66kv and 22kv distribution networks to supply the draglines, shovel and CPP.

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The Mineral Resources Act 1989 (Qld), or MRA, and the Mineral and Energy Resources (Common Provisions) Act 2014 (Qld), or MERCPA, together, provide for the assessment, development and utilization of mineral resources in Queensland to the maximum extent practicable, consistent with sound economic and land use management. The MRA vests ownership of minerals, with limited exceptions, in the “Crown,” which in relation to Curragh, is the Queensland Government. A royalty is payable to the Queensland Government for the right to extract minerals. The MRA also creates different tenures for different mining activities, such as prospecting, exploring and mining. A ML is the most important tenure, as it permits the extraction of minerals in conjunction with other required authorities. The MRA imposes general conditions on an ML.

We control the coal mining rights at Curragh under 14 coal and infrastructure MLs and three MDLs granted pursuant to the MRA. We refer to the MLs and MDLs at Curragh, collectively, as the Tenements. Renewal of certain Tenements will be required during the mine life of Curragh and the Queensland government can vary the terms and conditions on renewal. There are a number of existing mining and petroleum tenements which overlap with the Tenements. The priority, consent and coordination requirements under the MRA, MERCPA and the Petroleum and Gas (Production and Safety) Act 2004 (Qld) (as relevant) may apply with respect to those overlaps. Extensive statutory protocols govern the relationships between co-existing mining and exploration rights and these protocols are largely focused on encouraging the overlapping tenement holders to negotiate and formulate arrangements that enable the co-existence of their respective interests. To date, we have negotiated arrangements in place with all of our overlapping tenement holders and full access to all of our Tenements. See Item 1. “Business—Regulatory Matters—Australia—Tenements” for additional information regarding Curragh mining tenements.

Property control and mining rights at Curragh are entirely expressed in the MLs and MDLs mentioned in Item 1. “Business—Regulatory Matters—Australia—Tenements.” An overlapping petroleum tenure exists over the southern extents of the Tenements. Under the Mineral and Energy Resources (Common Provisions) Act 2014 (Qld), this requires annual information exchanges, including the provision and maintenance of joint information management plans with the overlapping tenement holder. Curragh is compliant with the legislation and there are no current restrictions to coal mining.

As conditions to certain of the Tenements, Curragh is subject to royalties payable to the Queensland government of 7.0% of revenues from coal sales to Stanwell (which could increase as described in Item 1. “Business—Regulatory Matters—Australia—Mineral Resources Act 1989 (Qld)”) and 8.22% to 10.42% of revenues from exported coal. These royalties are in addition to the Stanwell rebate, as described in Item 1. “Business—Customers—Stanwell.” Additionally, if MDL 162 advances from development to production, we would be required to pay under a private royalty deed a base royalty of A$0.50 per Mt of coal and a royalty of A$0.70 for every Mt of SCC produced above 2.5 MMt per year.

A joint venture between Arco Australia Ltd., Australian Consolidated Industries Ltd., R.W. Miller & Co. and Mitsui & Co. (Australia) first began development on certain of the Tenements in 1983. Later, Arco Australia Ltd. bought out the other joint venturers and, in 2000, sold the Property to Wesfarmers Ltd. In 2014, Wesfarmers acquired MDL 162 from Peabody Budjero Pty Ltd. Coronado acquired all the Tenements from Wesfarmers Ltd. in March 2018. Production history has been approximately 12.5 MMt in 2019, 12.0 MMt in 2020 and 11.1 MMt in 2021.

Beginning in the 1960’s, various tenement holders began prospecting and exploratory drilling at Curragh. We currently have an active, ongoing exploration program at Curragh that allows us to update and refine the geological model ahead of pit development.

Coal mine development at the Curragh property is presently accomplished by surface mining methods and has been so historically since the mine’s inception. The mine characteristics and output levels allow it to be ranked as a large coal operation when compared to domestic producers in Australia and worldwide. Curragh operates four large electric draglines, one large electric shovel and a fleet of smaller contractor excavators. Contractors are employed for the pre strip, post strip and coal mining activities. Curragh has two coal preparation plants CPP1 and CPP2. CPP1 is the oldest of the two processing plants and has a documented nameplate capacity of 1100 tph (as received). CPP2 has a documented nameplate capacity of 1200 tph (as received) with a capability of up to 1350 tph when processing selected feed types. Curragh has a loadout facility for loading coal onto railcars, which is connected to the main Blackwater rail link.

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Generally, the mining equipment and facilities at Curragh are in good operating condition. We focus on the long-term potential of the mine complex and regularly monitor developments in the mining industry for technology improvements and new equipment that could help us increase efficiency and lower our costs. Curragh’s oldest mining equipment, including two draglines, began operations in 1983. All of the draglines have additional boom (stress) monitoring systems, which allow us to increase their total suspended load capacities, and still achieve over 90% mechanical availability. Prior to our taking over mining operations, Wesfarmers Ltd. made improvements to the processing facilities at Curragh, including the commissioning of the second CPP in 2012 and replacing the raw coal crushing system at Curragh Main with an updated circuit in 2016. Wesfarmers Ltd. also started a corrosion and structural repair program over ten years ago that we have continued since acquiring the mine complex. This program helps us ensure that the assets are available well into the future. From time to time, we also update and improve other equipment and facilities to maintain their usefulness and optimize our competitiveness. As of December 31, 2021, the book value of Curragh and its associated plant and equipment was $791.0 million.

We are not aware of any significant encumbrances or defects in title with respect to the Property. We believe we have secured all applicable environmental licenses and permits under both Queensland and Australian Commonwealth legislation and have all permits and licenses regarding cultural heritage, native title and various other social issues. See Item 1. “Business—Regulatory Matters—Australia” for a discussion of the permitting conditions applicable to Curragh.

Summaries of Curragh’s coal resources and reserves as of December 31, 2021 are shown in Tables 4 and 5, respectively.

Table 4. Curragh – Summary of Coal Resources Exclusive of Reserves at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Curragh splits the resource into areas that are above and below a 15:1 open cut stripping ratio and considers the lower ratio areas as suitable for open cut mining at the higher ratio areas as suitable for underground mining. The average sales price for the underground resources was estimated to be $147 per Mt (FOB). Pricing for resources is described in Section 11.5 of the Curragh TRS.

(2)There are resources suitable for open cut mining outside of reserves. Pricing for resources is described in Section 11.5 of the Curragh TRS. Based on assumed long-term average sales price of $143 per Mt (FOB) representing the long-term average price forecast for Curragh based on independent price forecasts.

(3)Table 1-1 of the Curragh TRS provides a summary of Curragh resource tons inclusive of reserve tons as of December 31, 2021.

(4) Reported on a 5.3% in-situ moisture basis.

Table 5. Curragh – Summary of Coal Reserves (Marketable Sales Basis) at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1) Based on pricing data as provided by Coronado described in Section 16 of the Curragh TRS. The pricing data assumes average realized price of $141 per Mt sold over the LOM.

(2)Reported on an 11.0% moisture basis.

From December 31, 2020 to December 31, 2021, total reserves decreased by approximately 5%, from approximately 226.0 MMt to approximately 215.0 MMt. The decrease in total reserves is attributable to mining depletion.

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Barry Lay, BSc Geology (Hons); MAusIMM of Resology Pty Ltd, and Paul Wood, B. Eng.; MAusIMM(CP), who is employed full-time as the Senior Life of Mine Planner of our subsidiary, Coronado Curragh, whom we refer to as the Australian QPs, prepared the estimates of coal resources and reserves summarized in Tables 5 and 6. A copy of the Australian QPs’ technical report summary, or TRS, with respect to Curragh, dated February 21, 2022, or the Curragh TRS, is filed as Exhibit 96.1 hereto. Neither Mr. Barry Lay nor Resology Pty Ltd is affiliated with Coronado.

The Australian QPs prepared the estimates of coal resources and reserves using core drilling data available from exploration activities at Curragh conducted by numerous entities over time. Most of this information was obtained prior to our acquisition of the Property, using varying drilling and core-logging techniques, survey methods and testing procedures. As a result, in verifying the data, the Australian QPs made certain assumptions about the adequacy of the processes performed and comparability of the data based on their professional experience and familiarity with Curragh.

Per Section 12.1 of the Curragh TRS, coal reserves were classified as proven or probable considering “modifying factors,” including mining, metallurgical, economic, marketing, legal, environmental, social and governmental factors. Section 22.2 of the Curragh TRS includes a risk assessment of the key modifying factors that could potentially impact the operations and therefore the estimate of coal reserves and resources.

As summarized in Section 7.1 of the Curragh TRS, the concentration of exploration drill holes varies slightly across the Property. The location of the drilling is shown on the maps included in Section 7. Points of observation include exploration drill holes and mine measurements, which have been fully vetted and processed into a geologic model. The geologic model is based on seam depositional modelling, the interrelationship of overlying and underlying strata on seam mineability, seam thickness trends, the impact of seam structure (i.e., faulting), intra-seam characteristics, etc. Section 11.6 of the Curragh TRS summarizes the drill hole spacings and accuracy associated with each resource category.

Coal quality is instrumental in determining the viability of a coal deposit. As per Table 11-1 of the Curragh TRS, coal quality conforms to international standards. These quality attributes aided in converting in-place tons to demonstrated coal reserves (recoverable washed tons). Pricing data as provided by Coronado is described in Table 16-1 of the Curragh TRS. These are weighted-average values across the LOM schedule.

Regarding production rates as described in Section 13 of the Curragh TRS, the mine plan and productivity expectations consider historical performance and efforts have been made to adjust the plan to reflect current technology and future conditions. Mine development and operation have not been optimized within the Curragh TRS. Additional mine-specific factors can be found in Section 13 of the Curragh TRS.

Buchanan

Buchanan is a production-stage mining property, consisting of one active underground mine and supporting infrastructure that produces Low-Vol Met coal using the longwall mining method. The mine complex is located in Buchanan County in southwest Virginia. A map of Buchanan is shown in Figure 4.

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Figure 4. Coronado Buchanan Mine Complex Property Location Map.

The Buchanan mine complex is located approximately 6.4 kilometers southeast of Oakwood, Virginia, and 16 kilometers southeast of Grundy, Virginia. The coordinates of the Buchanan CPP are latitude 37° 09' 40" and longitude 81° 59' 13" (Easting 984,100’, Northing 320,100’ – in the VA State Plane South NAD 27 grid system). The nearest major population centers are Roanoke, Virginia, and Lexington, Kentucky, which are about 153 kilometers northeast and 290 kilometers northwest of the property, respectively. From U.S. Route 460, which runs through Oakwood, a well-developed network of improved and unimproved roads provides access to the property. The surface facilities at Buchanan are located along a Norfolk Southern rail line, which serves as the primary means of transport for produced coal. Norfolk Southern transports coal from the Buchanan mine complex either to domestic customers or to Lamberts Point Coal Terminal Pier 6 in Norfolk, Virginia, for overseas shipment.

Buchanan has ready access to water, electricity and personnel to support its operations. The mine complex sources water from streams that flow over Company-owned property. The mine also utilizes ground water from an old abandoned mine. Electricity is sourced from American Electric Power. Personnel have historically been sourced from the surrounding communities in Buchanan, Tazewell, McDowell and Pike Counties and have proven to be adequate in numbers to operate the mine complex. As mining is common in the surrounding areas, the workforce is generally familiar with mining practices and many are experienced miners.

The property mineral rights are composed of approximately 34,089 total hectares, of which 26,243 are leased or subleased from private landholders under approximately 150 individual coal lease tracts, and 7,846 hectares are owned by Coronado. Subject to Coronado’s exercising its renewal rights thereunder, all the leases expire upon exhaustion of the relevant coal reserves, which is expected to occur in 2047.

Under the terms of the relevant leases, we are required to pay royalties ranging from 3.5% to 6.0% of the selling price of coal mined from the corresponding leasehold and, for the majority, an annual minimum royalty, irrespective of production. Coal produced at Buchanan, however, is not subject to “wheelage fees” (i.e., fees payable on coal mined and removed from properties other than the particular leasehold and hauled across the leasehold premises).

The property was formerly controlled by Consolidation Coal Company, or CONSOL. Mine development was started by CONSOL in 1983 and longwall production began in 1987. Coronado acquired the Buchanan Mine from CONSOL in March 2016. Production history has been approximately 4.5 MMt in 2019, 3.4 MMt in 2020 and 4.4 MMt in 2021.

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Our right to commercially mine and recover coal reserves at Buchanan overlaps with the right of an affiliate of CNX Resources Corporation, which we refer to as the Gas Party, to commercially recover and develop coal gas interests from the mine area. The Gas Party and we have entered into certain agreements to regulate the interaction between, and coordinate, our respective operations. In general, the combination of these overlapping interests allows for mutual benefits to the parties, namely, the degassing of our coal mining operations in the mine, which helps assure the safety of mine personnel, and the Gas Party’s commercial capture and sale of the coal gas. In addition, the Gas Party’s drilling activities have contributed to exploration efforts with respect to coal deposits at Buchanan. As the only natural gas supplier in the area, we purchase our requirements of natural gas for the operation of our thermal dryer at Buchanan from the Gas Party.

Before Coronado took over mining operations at Buchanan, CONSOL Energy had conducted extensive exploration of the property. We have continued exploration at the property through a program of core drilling to confirm reserves, establish additional resources and assess the geotechnical viability of mining.

Buchanan produces primarily a Low-Vol HCC, but it also produces a premium Low-Vol PCI product. The Buchanan mine extracts coal from the Pocahontas #3 seam of the Pennsylvanian-age Pocahontas Formation, which is the principal minable coal seam of that formation. The seam is situated below drainage throughout the Property and is accessed by vertical shafts. The seam thickness averages 1.86 meters within the mining area.

The Buchanan mine extracts coal using a single longwall system supported by six continuous miner sections, which develop main entries and gate roads in preparation for the longwall. Each continuous miner section is equipped with one or two continuous miners, two roof bolters and two or three coal haulage units. After extraction, a series of conveyor belts deliver raw coal to an underground storage bunker. The Buchanan mine complex uses a skip hoist system to lift raw coal to the surface. Buchanan has a CPP that processes raw coal at a rate of approximately 1,270 raw tph, as well as the other necessary support infrastructure, including loadout and portal facilities.

Generally, the mining equipment and facilities at Buchanan are in good operating condition. We focus on the long-term potential of the mine complex and regularly monitor developments in the mining industry for technology improvements and new equipment that could help us increase efficiency and lower our costs. Since acquiring the Buchanan operations, we have implemented improvements at the CPP, which have resulted in increased capacity. From time to time, we also update and improve other equipment and facilities to maintain their usefulness and optimize our competitiveness. For example, we rebuild our longwall shear, drives and cycling shields after every panel. We have also entered into life cycle management agreements for our continuous miner equipment, installed programmable logic controller, or PLC, controls on the skip hoist system, upgraded our belt drives for increased horsepower, deployed state-of-the-art Fletcher roof bolters on our continuous miner sections and switched to PLC control systems and variable frequency drive, or VFD, starters on our belt drives. As of December 31, 2021, the book value of Buchanan and its associated plant and equipment was $367.0 million.

We are not aware of any significant encumbrances or defects in title with respect to the Property. Additionally, we believe we have obtained all requisite mining and discharge permits to conduct our operations at Buchanan and expect to be able to obtain all required permits in the future. The Buchanan mine complex holds one state permit, with the associated NPDES permit.

Buchanan is subject to a federal black lung excise tax of $1.21 per ton for underground mining and a federal reclamation tax of $0.13 per ton for underground mining. However, the federal black lung excise tax applies only with respect to coal sold domestically. Additionally, Buchanan is subject to a Virginia reclamation tax of $0.05 per ton (which amount is contributed to a state-funded bond pool) and a Virginia severance tax of 2% for all coal sold. See Item 1. “Business—Regulatory Matters—United States” for a discussion of the permitting conditions applicable to Buchanan.

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Summaries of Buchanan’s coal resources and reserves as of December 31, 2021 are shown in Tables 6 and 7, respectively.

Table 6. Buchanan – Summary of Coal Resources Exclusive of Reserves at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Pricing for resources is described in Section 11.3.1 of the Buchanan TRS. Based on assumed long-term average price of $94 per Mt (FOB loadout) representing the long-term average price forecast for Buchanan based on independent price forecasts.

(2) Exclusive of reserve tons. Table 1-1 of the Buchanan TRS provides a summary of Buchanan resource tons inclusive of reserve tons as of December 31, 2021.

(3)Reported on a dry basis. Surface moisture and inherent moisture are excluded.

Table 7. Buchanan – Summary of Coal Reserves (Marketable Sales Basis) at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Pricing data as provided by Coronado is described in Section 16.2 of the Buchanan TRS. The pricing data assumes a weighted average domestic and international FOB-mine price of approximately $197 per Mt for calendar year 2022. The weighted average price decreases to approximately $118 to $126 per Mt through year 2026 and averages approximately $152 per Mt over the LOM.

(2)Reported on a 6.0% moisture basis.

From December 31, 2020 to December 31, 2021, total reserves decreased by approximately 3%, from approximately 100.8 MMt to approximately 98.0 MMt. This net reduction of 2.8 MMt of total reserves was attributable to a combination of updates to the mine plan along with one year of mining depletion.

Michael G. McClure, CPG, and Justin S. Douthat, PE, MBA, of Marshall Miller & Associates, Inc., whom we refer to as the U.S. QPs, prepared the estimates of coal resources and reserves as of December 31, 2021 summarized in Tables 7 and 8. Both are full-time employees of Marshall Miller & Associates, Inc. and recognized as QPs. A copy of the U.S. QPs’ TRS with respect to Buchanan, dated as of February 18, 2022, or the Buchanan TRS, is filed as Exhibit 96.2 hereto. The U.S. QPs are not affiliated with Coronado.

The U.S. QPs prepared the estimates of coal resources and reserves using core drilling data available from exploration activities at Buchanan conducted by numerous entities over time. Most of this information was obtained prior to our acquisition of the property, using varying drilling and core-logging techniques, survey methods and testing procedures. As a result, in verifying the data, the U.S. QPs made certain assumptions about the adequacy of the processes performed and comparability of the data based on their professional experience and familiarity with Buchanan.

Per Section 12.1 of the Buchanan TRS, coal reserves were classified as proven or probable considering “modifying factors,” including mining, metallurgical, economic, marketing, legal, environmental, social and governmental factors. Section 22.2 of the Buchanan TRS includes a risk assessment of the key modifying factors that could potentially impact the operations and therefore the estimate of coal reserves and resources.

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As summarized in Section 7.1 in the Buchanan TRS, the U.S. QPs utilized 4,535 available core, rotary, and coalbed methane wells on and around the Buchanan property. Points of observation include exploration drill holes, degas holes, and mine measurements, which have been fully vetted and processed into a geologic model. The geologic model is based on seam depositional modeling, the interrelationship of overlying and underlying strata on seam mineability, seam thickness trends, the impact of seam structure (i.e., faulting), intra-seam characteristics, etc. The U.S. QPs completed a geostatistical analysis on drill holes within the reserve boundaries to determine the applicability of the common United States classification system for measured and indicated coal resources. Historically, the United States has assumed that coal within 0.4 kilometers of a point of observation represents a measured resource, whereas coal between 0.4 kilometers and 1.2 kilometers from a point of observation is classified as indicated. Inferred resources are commonly assumed to be located between 1.2 kilometers and 4.8 kilometers from a point of observation. The U.S. QPs performed a geostatistical analysis of the Buchanan data set using the Drill Hole Spacing Analysis, or DHSA, method. DHSA prescribes that measured, indicated and inferred drill hole spacings be determined at the 10%, 20%, and 50% levels of relative error, respectively. Comparing the results of the DHSA to the historical standards, it is evident that the historical standards are more conservative than even the most conservative DHSA model with regards to determining measured resources. The Exponential model included in the DHSA recommends using a radius of 0.67 kilometers for measured resources compared to the historical value of 0.4 kilometers. With respect to indicated resources the DHSA falls in line closely with the historical standards. The Exponential and Spherical models of the DHSA recommend using a radius of 1.08 kilometers from a point of observation for indicated resources, while the Gaussian model included in the DHSA recommends a radius of 1.10 kilometers from a point of observation for indicated resources. These values line up closely with the historical radius of 1.2 kilometers. These results have led the U.S. QPs to report the data following the historical classification standards, rather than use the results of the DHSA.

Coal quality is instrumental in determining the viability of a coal deposit. Per Section 8.2 of the Buchanan TRS, coal quality conforms to the American Society for Testing and Materials, or ASTM, standards. These quality attributes aided in converting dry, in-place tons to demonstrated coal reserves (recoverable washed tons). The reserve and resource criteria are presented in Table 11-1 of the Buchanan TRS, including assumptions related to seam density, minimum cut-off thickness, and recoveries.

Regarding production rates as described in Section 13.2 of the Buchanan TRS, the mine plan and productivity expectations reflect historical performance and efforts have been made to adjust the plan to reflect future conditions. Mine development and operation have not been optimized within the Buchanan TRS.

Logan

Coronado’s Logan property is currently in the production stage. Logan consists of four active underground mines (Powellton No. 1, Lower War Eagle, Eagle No. 1 and Muddy Bridge) and supporting infrastructure that produce High-Volatile Met coal using the room and pillar mining method and one active surface mine (Toney Fork) and supporting infrastructure that produce both Met and thermal coal using the contour and highwall mining methods. The Logan complex life plan includes 12 proposed mines, consisting of nine underground mines and three surface mines. The property is located in Boone, Logan and Wyoming Counties in southern West Virginia. The surface facilities are located in Logan County, West Virginia. A map of Logan is shown in Figure 5.

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Figure 5. Coronado Logan Mine Complex Property Location Map.

The Logan mine complex encompasses the towns of Lorado and Pardee in Logan County, West Virginia, and Cyclone and Lacoma in Wyoming County, West Virginia. The coordinates of the Saunders CPP are latitude 37° 47' 58" and longitude 81° 40' 01" (Easting 1,806,880’, Northing 291,517’ – in the WV State Plane South NAD 27 grid system). The nearest major population centers are Huntington, West Virginia, and Charleston, West Virginia, which are about 145 kilometers northwest and 129 kilometers northeast of the property, respectively. From U.S. Route 119, which runs through Mingo, Logan and Boone Counties to the north, a well-developed network of improved and unimproved roads provides access to the property, including Route 16 and Route 10, which run east-west across the property in Logan County and Wyoming County, respectively. The Logan surface facilities are located approximately 21 kilometers northeast of Man, West Virginia, along a CSX Corporation, or CSX, rail line, which serves as the primary means of transport for produced coal. CSX transports coal from Logan either to domestic customers or to the Kinder Morgan Pier IX and Dominion Terminals in Norfolk, Virginia, for overseas shipment.

Logan has ready access to water, electricity and personnel to support its operations. Buffalo Creek Public Service District supplies water and American Electric Power supplies electricity to the mine complex. Mine personnel generally live in the surrounding communities of Logan, Boone, Wyoming and Mingo Counties in West Virginia.

The property mineral rights are composed of 13,138 total hectares, 13,069 of which are leased from private landholders under approximately 15 individual leases, and 69 hectares are owned by Coronado. Subject to Coronado exercising its renewal rights thereunder, a majority of the leases, covering a majority of the Logan reserves, expire upon exhaustion of the relevant coal reserves, which is expected to occur in 2053. One lease expires in 2032; however, Coronado is projected to have previously exhausted the reserves covered thereby.

Under the terms of the leases, we are required to pay royalties ranging from 3.0% to 9.0% of revenue from sales of coal produced depending on mining method. Certain of the leases also provide for “wheelage fees” ranging from 0.25% to 1.0% of revenue from sales of coal mined and removed from properties other than the particular leasehold and hauled across the leasehold premises.

The mining of Logan was commenced in 1945 by Lorado Mining Company, or Lorado. Lorado was sold to Buffalo Mining Company in 1964 and then to Pittston Coal Company in 1971. Pittston operated the property until the early 1990’s. After being idle for a period, the property was then sold to Addington Resources in 2004. Imagin Natural Resources acquired the property in 2007 and sold it to Cliffs Natural Resources Inc. (now known as Cleveland-Cliffs Inc.) in 2011, which in turn sold the property to Coronado in 2014. Production history has been approximately 2.7 MMt in 2019, 1.6 MMt in 2020 and 1.9 MMt in 2021.

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Before Coronado acquired Logan, previous owners had conducted extensive exploration on the property. Coronado has continued exploration at the property through a program of core drilling to confirm reserves, establish additional resources and assess the geotechnical viability of mining.

Logan produces primarily High-Vol Met coal (HVA HCC and HVB HCC), mined from various seams of the Kanawha Formation, most of which are situated below drainage; however, several Met coal seams are situated above drainage. Logan also produces thermal coal from upper portions of the Kanawha Formation.

Most of Logan’s Met coal production is attributable to its four active underground mines, Powellton No. 1, Lower War Eagle, Eagle No. 1 and Muddy Bridge, each of which uses the room and pillar mining method. The Powellton No. 1 mine utilizes one continuous miner super section to extract coal from the Upper Powellton seam, which is situated above or below drainage, depending on the relief of the property, and accessed by a shallow slope and crop. The Lower War Eagle mine utilizes two continuous miner super sections to extract coal from the Lower War Eagle seam, which is situated below drainage throughout the property and accessed by slope. The Eagle No. 1 mine utilizes three continuous miner super sections to extract coal from the No. 2 Gas seam, which is situated above drainage throughout the property and accessed by drift entry. The Muddy Bridge mine utilizes two continuous miner super sections to extract coal from the No. 2 Gas seam, which is situated above drainage throughout the property and accessed by drift entry.

A majority of the sections of the active underground mines at Logan are configured as full super sections, with two continuous miners per section. Each section also has two or four roof bolters, three or six shuttle cars and two scoops. From the continuous miner at the production face, the shuttle cars haul extracted coal to a feeder breaker, which transfers raw coal to a conveyor belt for transport to a surface stockpile holding area. A shared overland conveyor carries raw coal from the Powellton No. 1 and Lower War Eagle mines to a CPP. Trucks haul raw coal from the Eagle No. 1 mine to the CPP and from the Muddy Bridge mine to the Logan overland conveyor. The CPP has a feed rate capacity of 1,088 raw tph. The CPP site includes raw coal storage, clean coal storage, a loadout connected to a CSX rail line and refuse disposal area.

The Toney Fork surface mine extracts Met and thermal coal using the area mining method. The current LOM plan for Toney Fork also contemplates utilizing contour and highwall mining methods at various times during the life of the mine. The mine uses a spread of front-end loaders, large tractors/dozers and rock trucks to remove overburden and expose the coal. We will deploy highwall mining when overburden volumes exceed economical stripping ratios associated with area and contour mining. Trucks haul raw coal from Toney Fork to the CPP site for cleaning or to the loading site to be shipped directly to customers.

Our current plans at Logan contemplate 12 proposed mines, consisting of nine underground mines and three surface mines, including the five mines currently in operation. The proposed underground mines would extract coal using the room and pillar mining method, and the proposed surface mines would extract coal using area, contour or highwall mining methods, or some combination thereof.

Generally, the mining equipment and facilities at Logan are in good operating condition. We focus on the long-term potential of the mine complex and regularly monitor developments in the mining industry for technology improvements and new equipment that could help us increase efficiency and lower our costs. Logan’s oldest mining equipment and facilities, including the CPP and loadout facility, began operations in 2008, when the Powellton No. 1 mine started production. Since acquiring the Logan operations, we have implemented improvements at the CPP, which have resulted in increased capacity. From time to time, we also update and improve other equipment and facilities to maintain their usefulness and optimize our competitiveness. As of December 31, 2021, the book value of Logan and its associated plant and equipment was $226.2 million.

We are not aware of any significant encumbrances or defects in title with respect to the property. Additionally, we believe we have obtained all requisite mining and discharge permits to conduct our operations at Logan and expect to be able to obtain or renew all required permits in the future. The Logan mine complex holds 25 state permits with associated NPDES permits.

Logan is subject to a federal black lung excise tax of $1.21 per ton for underground mining and $0.28 per ton for surface and highwall mining; however, this tax applies only with respect to coal sold domestically. Logan is also subject to a federal reclamation fee of $0.13 per ton for underground mining and $0.31 per ton for surface and highwall mining. Additionally, Logan is subject to a West Virginia reclamation tax of $0.308 per ton and a West Virginia severance tax of 1.0% to 5.0% of revenues for all coal produced. See Item 1. “Business—Regulatory Matters—United States” for a discussion of the permitting conditions applicable to Logan.

Summaries of Logan’s coal resources and reserves as of December 31, 2021 are shown in Tables 8 and 9, respectively.

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Table 8. Logan – Summary of Coal Resources Exclusive of Reserves at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Pricing for resources is described in Section 11.3.1 of the Logan TRS. Based on assumed long-term average price of $130 per ton (FOB loadout) for underground-mineable resources, representing the long-term average price forecast for HVB provided by Coronado. Surface resources were assessed at a sales price of $52 per Mt (FOB loadout) based on estimated historical pricing for Coronado’s surface operations.

(2)Exclusive of reserve tons. Table 1-1 of the Logan TRS provides a summary of Logan resource tons inclusive of reserve tons as of December 31, 2021.

(3)Reported on a dry basis. Surface moisture and inherent moisture are excluded.

Table 9. Logan – Summary of Coal Reserves (Marketable Sales Basis) at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Pricing data as provided by Coronado is described in Section 16.2 of the Logan TRS. The pricing data assumes respective HVA, HVB, specialty markets and thermal FOB-mine prices of approximately $224, $123, and $51 per Mt for calendar year 2022. HVA, HVB, and thermal prices decrease to approximately $145, $115, and $51 per Mt, respectively, through year 2026, and then increase to $227, $189, and $51 per Mt, respectively, through year 2050 (after which sales prices were held constant).

(2) Reported on a 4.5% - 6.0% moisture basis.

From December 31, 2020 to December 31, 2021, total reserves decreased by approximately 2.0%, from approximately 75.0 MMt to 73.5 MMt. This net reduction of 1.5 MMt of total reserves was attributable to a combination of updates to the mine plans along with one year of mining depletion.

John W. Eckman, CPG, and Justin S. Douthat, PE, MBA, of Marshall Miller & Associates, Inc., whom we refer to as the U.S. QPs, prepared the estimates of coal resources and reserves as of December 31, 2021 summarized in Tables 9 and 10. Both are full-time employees of Marshall Miller & Associates, Inc. and recognized as QPs. A copy of the U.S. QPs’ TRS with respect to Logan, dated as of February 18, 2022, or the Logan TRS, is filed as Exhibit 96.3 hereto. The U.S. QPs are not affiliated with Coronado.

The U.S. QPs prepared the estimates of coal resources and reserves using core drilling data available from exploration activities at Logan conducted by numerous entities over time. Most of this information was obtained prior to our acquisition of the property, using varying drilling and core-logging techniques, survey methods and testing procedures. As a result, in verifying the data, the U.S. QPs made certain assumptions about the adequacy of the processes performed and comparability of the data based on their professional experience and familiarity with Logan. Per Section 12.1 of the Logan TRS, coal reserves were classified as proven or probable considering “modifying factors,” including mining, metallurgical, economic, marketing, legal, environmental, social and governmental factors. Section 22.2 of the Logan TRS includes a risk assessment of the key modifying factors that could potentially impact the operations and therefore the estimate of coal reserves and resources.

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As summarized in Section 7.1 in the Logan TRS, the U.S. QPs utilized 1,127 available core, rotary, and gas well drilling on and around the Logan property. Points of observation include exploration drill holes, degas holes, and mine measurements, which have been fully vetted and processed into a geologic model. The geologic model is based on seam depositional modeling, the interrelationship of overlying and underlying strata on seam mineability, seam thickness trends, the impact of seam structure (i.e., faulting), intra-seam characteristics, etc. The U.S. QPs completed a geostatistical analysis on drill holes within the reserve boundaries to determine the applicability of the common United States classification system for measured and indicated coal resources. Historically, the United States has assumed that coal within 0.4 kilometers of a point of observation represents a measured resource whereas coal between 0.4 kilometers and 1.2 kilometers from a point of observation is classified as indicated. Inferred resources are commonly assumed to be located between 1.2 kilometers and 4.8 kilometers from a point of observation. The U.S. QPs performed a geostatistical analysis of the Logan data set using the DHSA method. DHSA prescribes measured, indicated, and inferred drill hole spacings be determined at the 10%, 20%, and 50% levels of relative error, respectively. Comparing the results of the DHSA to the historical standards, it is evident that the historical standards are more conservative than even the most conservative DHSA model with regards to determining measured resources. The Exponential and Spherical models recommend using a radius of 0.87 kilometers for measured resources compared to the historical value of 0.4 kilometers. With respect to indicated resources the Spherical and Exponential models recommend using a radius 1.53 kilometers. The historical radius of 1.2 kilometers is therefore also more conservative than the DHSA results for indicated resources. These results have led the U.S. QPs to report the data following the historical classification standards, rather than use the results of the DHSA.

Coal quality is instrumental in determining the viability of a coal deposit. Per Section 8.2 of the Logan TRS, coal quality conforms to the ASTM standards. These quality attributes aided in converting dry, in-place tons to demonstrated coal reserves (recoverable washed tons). The reserve and resource criteria are presented in Table 11-1 of the Logan TRS, including assumptions related to seam density, minimum cutoff thickness, and recoveries. Pricing data as provided by Coronado is described in Section 16.2 of the Logan TRS.

Regarding production rates as described in Section 13.2 of the Logan TRS, the projected underground mines are set up similarly to the four active underground operations as of December 31, 2021. Each mine is scheduled to operate one to three production sections. All sections are configured as full super sections with two continuous miners per section. Three surface resource areas were modeled. Mining operations are projected to utilize area, as well as contour, mining methods. The three areas planned for highwall mining are assumed to be mined by a contractor; therefore, the contractor costs included in the financial model assume that the contractor is responsible for staffing those operations along with providing necessary equipment capital. Spoil for final highwall reclamation is expected to come from strategic placement of spoil on pre-existing benches by haul trucks such that they are within the push distance of the reclamation dozer. Additional information regarding mine-specific production factors can be found in Section 13.4 of the Logan TRS.

Mon Valley

The Mon Valley mine complex comprises three development-stage mining properties, namely, Pangburn, Shaner and Fallowfield, each consisting of a proposed underground mine that would produce High-Vol Met coal using the room and pillar mining method. The preliminary design for the properties also includes plans for surface facilities and a preparation plant for each mine. The properties reside in Allegheny, Washington and Westmoreland Counties in southwestern Pennsylvania. The proposed facilities include a barge loading dock and CSX rail loadout on the Monongahela River in Allegheny County, Pennsylvania, which would ship clean coal from all three mines to end customers. A map of Mon Valley is shown in Figure 6.

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Figure 6. Coronado Mon Valley Mine Complex Property Location Map.

Mon Valley is located approximately 22.5 kilometers southeast of Pittsburgh, Pennsylvania, near the communities of Bentleyville, Lockview, Monongahela, Elizabeth, Sutersville and Irwin, Pennsylvania. The coordinates of the proposed infrastructure are latitude 40° 15' 24" and longitude 79° 53' 50" (Easting 1,398,821’, Northing 343,480’ – in the PA State Plane South NAD 27 grid system). From U.S. Interstate 70 and Pennsylvania Route 51, which traverse the Fallowfield and Pangburn areas, respectively, a well-developed network of improved and unimproved roads allows general access to the property. The Monongahela and Youghiogheny Rivers also run through the property. The primary means of transport for produced coal would be by barge on the Monongahela River/Ohio River system. Additionally, a CSX rail line located along the banks of the Monongahela River would provide another option for the shipment of coal.

Mon Valley has sources of water, power, and supplies readily available for use. Personnel in the area have historically been sourced from the surrounding communities in Allegheny, Washington, and Westmoreland Counties, and have proven to be adequate in numbers to operate the mines. As mining is common in the surrounding areas, the workforce is generally familiar with mining practices, and many are experienced miners. Water is expected to be sourced locally from a nearby public water sources or rivers. Electricity is anticipated to be sourced from West Penn Power. The service industry in the areas surrounding the proposed mine complex has historically provided supplies, equipment repairs and fabrication, etc.

The property mineral rights are composed of 41,615 total hectares, of which 1,339 are leased from private landholders under two leases, and 40,276 hectares are owned by Coronado. Subject to Coronado’s exercising its renewal rights thereunder, both of the leases expire upon exhaustion of the relevant coal reserves, which is expected to occur in 2099.

A predecessor of CONSOL Energy previously controlled the properties. We acquired the properties from CONSOL Energy in March 2016 in connection with the acquisition of the Buchanan property.

Before we acquired Mon Valley, CONSOL Energy had conducted extensive exploration of Mon Valley. We have continued an exploration program focused on defining reserves and assessing the geotechnical viability of mining.

Mon Valley is capable of producing primarily a High-Vol Met coal from the Upper Freeport seam of the Pennsylvania-age Allegheny Formation. The seam is situated below drainage throughout the properties and would be accessed with slopes and shafts. The seam thickness in the projected mining areas averages 1.95 meters.

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Under our current mine development plans, production would begin at the Pangburn mine in 2031, followed by the Shaner mine in 2037 and, finally, the Fallowfield mine in 2056. The proposed Mon Valley underground mines would use the room and pillar mining method with limited pillaring as to cause no subsidence. Each mine would have three continuous miner sections, with two continuous miners, two roof bolters, four shuttle cars and two scoops per section. The shuttle cars would haul extracted coal from the production face to a feeder breaker-conveyor system, which would carry raw coal to a surface stockpile and CPP. The CPPs and surface facilities would have large raw and clean coal storage areas to facilitate efficient loading of clean coal into barges or rail cars for transport. We have not yet completed detailed designs of the infrastructure or surface facilities for the proposed Shaner and Fallowfield mines.

As of December 31, 2021, the book value of Mon Valley was $17.4 million.

We are not aware of any significant encumbrances or defects in title with respect to the properties. However, we will be required to obtain alternate zoning approval from the local township. Further, we will be required to submit formal permit applications to state or federal regulatory agencies. Although we have commenced the work to obtain the necessary permits and zoning variances, we are aware that the period of time necessary to obtain final authorizations, for purposes of commencing the development, construction and ultimate production at the proposed mine site, may be significant, and there can be no assurance that we can obtain the necessary zoning and permits. See Item 1. “Business—Regulatory Matters—United States” for a discussion of the permitting conditions applicable to Mon Valley.

Coal mined from the Mon Valley mine complex would be subject to a federal black lung excise tax of $1.21 per ton for underground mining and a federal reclamation tax of $0.13 per ton for underground mining. However, the federal black lung excise tax will only apply with respect to coal sold domestically.

Mon Valley contains no resources exclusive of reserve tons as of December 31, 2021. Table 1-1 of the Mon Valley TRS provides a summary of Mon Valley resource tons inclusive of reserve tons as of December 31, 2021.

A summary of Mon Valley’s coal reserves as of December 31, 2021 is shown in Table 10.

Table 10. Mon Valley – Summary of Coal Reserves (Marketable Sales Basis) at the End of the Fiscal Year Ended December 31, 2021.⁽¹⁾

(1)Pricing data as provided by Coronado is described in Section 16.2 of the Mon Valley TRS. The pricing data assumes HVB domestic and export FOB-mine prices of approximately $137 and $120 per Mt, respectively, for calendar year 2027. HVB domestic and export prices increase to approximately $221 and $193 per Mt, respectively, through year 2050, and then increased by 1% annual inflation thereafter.

(2) Reported on a 6.0% moisture basis.

Total reserves did not change from December 31, 2020 to December 31, 2021.

Scott Peterson, CPG, and Justin S. Douthat, PE, MBA, of Marshall Miller & Associates, Inc., whom we refer to as the U.S. QPs, prepared the estimates of coal resources and reserves summarized in Tables 13 and 14. Both are full-time employees of Marshall Miller & Associates, Inc. and recognized as QPs. A copy of the U.S. QPs’ TRS with respect to Mon Valley (Pennsylvania Upper Freeport Holdings), dated as of February 18, 2022, or the Mon Valley TRS, is filed as Exhibit 96.4 hereto. The U.S. QPs are not affiliated with Coronado.

The U.S. QPs prepared the estimates of coal resources and reserves using core drilling data available from exploration activities at Mon Valley conducted by numerous entities over time. Most of this information was obtained prior to our acquisition of the Property, using varying drilling and core-logging techniques, survey methods and testing procedures. As a result, in verifying the data, the U.S. QPs made certain assumptions about the adequacy of the processes performed and comparability of the data based on their professional experience and familiarity with Mon Valley.

Per Section 12.1 of the Mon Valley TRS, coal reserves were classified as proven or probable considering “modifying factors,” including mining, metallurgical, economic, marketing, legal, environmental, social and governmental factors. Section 22.2 of the Mon Valley TRS includes a risk assessment of the key modifying factors that could potentially impact the operations and therefore the estimate of coal reserves and resources.

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As summarized in Section 7.1 in the Mon Valley TRS, the U.S. QPs utilized approximately 750 available core and rotary holes on and around the Mon Valley properties. Points of observation include exploration drill holes, degas holes, and mine measurements, which have been fully vetted and processed into a geologic model. The geologic model is based on seam depositional modeling, the interrelationship of overlying and underlying strata on seam mineability, seam thickness trends, the impact of seam structure (i.e. faulting), intra-seam characteristics, etc. The U.S. QPs completed a geostatistical analysis on drill holes within the reserve boundaries to determine the applicability of the common United States classification system for measured and indicated coal resources. Historically, the United States has assumed that coal within 0.4 kilometers of a point of observation represents a measured resource whereas coal between 0.4 kilometer and 1.2 kilometers from a point of observation is classified as indicated. Inferred resources are commonly assumed to be located between 1.2 kilometers and 4.8 kilometers from a point of observation. The U.S. QPs performed a geostatistical analysis of the Pennsylvania data set using the DHSA method. DHSA prescribes measured, indicated, and inferred drill hole spacings be determined at the 10-percent, 20-percent, and 50-percent levels of relative error, respectively. Comparing the results of the DHSA to the historical standards, it is evident that the historical standards are more conservative than even the most conservative DHSA model with regards to determining measured resources. The Gaussian and Spherical models recommend using a radius of 0.72 kilometers for measured resources compared to the historical value of 0.4 kilometers. With respect to indicated resources the DHSA falls in line closely with the historical standards. The Exponential model recommends using a radius 1.43 kilometers, while the Spherical and Gaussian models recommend a radius of 1.42 kilometers, respectively. These values line up closely with the historical radius of 1.2 kilometers. These results have led the U.S. QPs to report the data following the historical classification standards, rather than use the results of the DHSA.

Coal quality is instrumental in determining the viability of a coal deposit. Per Section 8.2 of the Mon Valley TRS, coal quality conforms to the ASTM standards. These quality attributes aided in converting dry, in-place tons to demonstrated coal reserves (recoverable washed tons). The reserve and resource criteria are presented in Table 11-1 of the Mon Valley TRS, including assumptions related to seam density, minimum cutoff thickness, and recoveries. Pricing data as provided by Coronado is described in Section 16.2 of the Mon Valley TRS.

Regarding production rates as described in Section 13.2 of the Mon Valley TRS, the Mon Valley mine complex is not yet active, with three distinct mines and CPPs planned. The mine plan and productivity expectations reflect historical performance from other similar mines with similar conditions and efforts have been made to adjust the plan to reflect future conditions. Mine development and operation have not been optimized within the Mon Valley TRS. Additional mine-specific factors can be found in Section 13.4 of the Mon Valley TRS.

Greenbrier (Non-Material Property)

The Greenbrier property has been idled since April 1, 2020. During the fourth quarter of 2020, the Company committed to a plan to sell Greenbrier on the basis that it does not form part of the Company’s core business strategy. The Greenbrier property is not considered material to Coronado’s business or financial conditions. Resources exclusive of reserves are based on assumed long-term average price of $122 per ton (FOB loadout) for underground-mineable resources and between $116 to $120 per Mt (FOB loadout) for surface/highwall mining resources, representing the Company’s long-term average price forecast for Greenbrier. The pricing data assumes respective Mid-Vol, Low-Vol and thermal/PCI FOB-mine prices of approximately $147, $137 and $76 per Mt for calendar year 2027. Mid-Vol, Low-Vol and thermal/PCI prices increase to approximately $196, $181 and $102 per Mt, respectively, through year 2040. The Greenbrier operations are projected to be fully depleted in 2042. Marketable reserve tons are reported on a moist basis, including a combination of surface and inherent moisture. The combination of surface and inherent moisture is modeled at 6.0%.

Russell County (Non-Material Property)

The Russell County property is not considered material to Coronado’s business or financial conditions. In addition, pursuant to the current mine plan, the property will only start generating cash flows when it commences production in 2039. Resources exclusive of reserves are based on assumed long-term average price of $125 to $128 per Mt (FOB loadout), representing the Company’s long-term average price forecast for Russell County. The pricing data assumes HVA FOB-mine prices with a weighted LOM average of approximately $208 per Mt. Marketable reserve tons are reported on a moist basis, including a combination of surface and inherent moisture. The combination of surface and inherent moisture is modeled at 6.0%.

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Internal Controls

Our staff of geologists and engineers worked with the qualified persons throughout the mineral resource and reserve estimation process and provided data from our own exploration and operating activities at the properties. We have internal control procedures, including quality assurance/quality control procedures and internal verification of input data and geological modelling, subject to multi-level review, to help ensure the validity of the data. These procedures include, but are not limited to:

•Oversight and approval of each annual statement by responsible senior officers;

•Independent, external review of new and materially changed estimates at regular intervals;

•Annual reconciliation with internal planning by our staff of geologists and engineers to validate coal reserve and coal resource estimates for operating mines, including the following procedures:

•Assessments of drilling, sampling and quality assurance/quality control data, resource modelling, resource estimation, classification, and reporting;

•Assessment and benchmarking of production assumptions, mining rate and production schedules against historical production data;

•Assessments of capital and operating costs against other comparable projects for reasonableness;

•Continual identification and evaluation of material technical issues likely to impact the five-year plan and the future performance of producing properties;

•An examination of historical information and results in respect of the technical aspects of the properties by our staff of geologists and engineers, including a review of the following key elements:

•Geology mapping, reports and models, including geotechnical and hydrology aspects;

•Coal resource and coal reserve estimates;

•Mining operations and proposed growth options;

•Coal preparation facilities;

•Coal handling and transport;

•Environmental matters and approvals;

•Land management, including leases and other pertinent agreements;

•Veracity of existing information supporting five-year plans and business plans;

•Identification of key project drivers; and

•Risks and opportunities.

The pricing information used for preliminary resource valuation and to estimate our proven and probable coal reserves was based on prices under our existing contracts and price forecasts. Below is a description of some of the factors that could affect price forecasts for Met and thermal coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in the price forecasts and realized factors could cause actual pricing to differ from the forecasts.

Metallurgical. Several factors can influence Met coal supply and demand and pricing. Demand is impacted by economic conditions and demand for steel and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

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Seaborne Met coal import demand can be significantly impacted by the availability of local coal production, particularly in leading Met coal import countries such as China and India, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne Met coal supply from leading Met coal exporting countries, such as Australia, the United States, Russia, Canada and Mongolia, among others, is also an important price consideration.

In addition to the factors noted above, the prices which may be obtained at each individual mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.

Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix, changes in capacity (additions and retirements), inter-basin or inter-country coal competition, coal stockpiles and policy and regulations. Supply considerations impacting pricing include reserve positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (new mine developments or extensions at existing mines).

The cost information that the QPs used for preliminary resource valuation and to estimate our proven and probable reserves were generally internal projected future costs based on historical costs and expected future trends. The estimated costs normally include mining, processing, transportation, royalty, tax and other mining-related costs. Our estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, natural gas, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and tax) are based on contractual prices or fixed rates. Specific factors that may impact the cost at our various operations include:

•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides geological models for the life-of-mine process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.

•Scale of operations and the equipment sizes. For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than bord-and-pillar operations for underground mines.

•Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof bolts represents a significant cost. Commodity price forecasts are used to project those costs in the financial models we use to establish our reserves.

•Target product quality. By targeting a premium quality, product, our mining and processing processes may experience more coal losses. By lowering product quality, the coal losses can be minimized and therefore a lower cost per Mt can be achieved. In our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands.

•Transportation costs. We have entered into arrangements with third parties to gain access to transportation infrastructure and services where required, including rail carriers and port owners. Where coal is exported or sold other than at the mine gate, the costs associated with these arrangements represent a significant portion of both the total cost of supplying coal to customers and of our production costs. As a result, the cost of transportation is not only a key factor in our cost base but also in the purchasing decision of customers. Our transportation costs vary by region. See Item 1. “Business—Transportation” for more information regarding transportation arrangements for our operations.

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•Royalty costs. As conditions to certain of the Tenements, Curragh is subject to royalties payable to the Queensland government as described in Item 1. “Business—Regulatory Matters—Australia—Mineral Resources Act 1989 (Qld)”). These royalties are in addition to the Stanwell rebate, as described in Item 1. “Business—Customers—Australia Sales and Marketing—Stanwell.” Royalty costs at our U.S. Operations are based upon contractual agreements for the coal leased from private owners and vary from property to property and by the type of mine (i.e., surface or underground). The royalty rates under leases at our U.S. Operations range between 3% - 9% of revenues from coal sales. Under some of the leases, we are required to pay minimum royalties, regardless of production, and/or “wheelage fees” (i.e., fees payable on coal mined and removed from properties other than the particular leasehold and hauled across the leasehold premises).

•Black lung, severance and reclamation taxes. Our U.S. Operations are subject to a federal black lung excise tax on coal sold domestically.

•Exchange rates. Costs related to our Australian Operations are predominantly denominated in A$, while the coal that our Australian Operations export is sold in US$. As a result, A$-US$ exchange rates impact the U.S. dollar cost of our Australian Operations’ production.

For further discussion of comprehensive risk inherent in the estimation, see Item 1A. “Risk Factors—Operational and Technology Risks—We rely on estimates of our recoverable resources and reserves, which are complex due to geological characteristics of the properties and the number of assumptions made.”

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ITEM 3. LEGAL PROCEEDINGS.

We are involved in various legal proceedings occurring in the ordinary course of business. It is the opinion of management, after consultation with legal counsel, that these matters will not materially affect our consolidated financial position, results of operations or cash flows.

The Company is subject to a wide variety of laws and regulations within the legal jurisdiction in which it operates. See “Part I, Item 1. Business—Regulatory Matters” for additional information. The Company believes that it is in substantial compliance with federal, state and local laws and regulations.

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ITEM 4. MINE SAFETY DISCLOSURES

Safety is the cornerstone of the Company’s values and is the number one priority for all employees at Coronado Global Resources.

Our U.S. Operations include multiple mining complexes across three states and are regulated by both the U.S. Mine Safety and Health Administration, or MSHA, and state regulatory agencies. Under regulations mandated by the Federal Mine Safety and Health Act of 1977, or the Mine Act, MSHA inspects our U.S. mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act.

In accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104), each operator of a coal or other mine is required to report certain mine safety results in its periodic reports filed with the SEC under the Exchange Act.

Information pertaining to mine safety matters is included in Exhibit 95.1 attached to this Annual Report on Form 10-K. The disclosures reflect the United States mining operations only, as these requirements do not apply to our mines operated outside the United States.

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ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our CDIs, each representing one-tenth of one share of our common stock, have been listed on the ASX under the trading symbol “CRN” since October 23, 2018. Prior to such time, there was no public market for our securities. There is no principal market in the United States for our CDIs or shares of our common stock.

Holders

As of December 31, 2021, we had 167,645,373 shares of our common stock issued and outstanding with 5,278 holders of record. The holders included CHESS Depositary Nominees Pty Limited, which held 90,337,270 shares of our common stock in the form of CDIs on behalf of the CDI holders; there were 5,277 registered owners of our CDIs on December 31, 2021.

Series A Preferred Share

On September 20, 2018, we issued the Series A Preferred Share to Coronado Group LLC, at par value. The offer, sale, and issuance of the Series A Share were deemed to be exempt from registration under the Securities Act in reliance on Section 4(a)(2) of the Securities Act as transactions by an issuer not involving a public offering. The recipient of the Series A Share acquired the Series A Share for investment only and not with a view to or for sale in connection with any distribution thereof and appropriate legends were affixed to the Series A Share.

Dividends

The payment of dividends is at the discretion of the Board of Directors. The decision as to whether or not a dividend will be paid will be subject to a number of considerations including the general business environment, operating results, cash flows, future capital requirements, regulatory and contractual restrictions, as well as applicable covenants under the indenture governing our senior secured notes and covenants under the ABL Facility and any other factors the Board of Directors may consider relevant.

Our objective in setting our dividend policy is to deliver stockholder returns while maintaining flexibility to pursue our strategic initiatives within a prudent capital structure. Our dividend policy is to distribute between 60% and 100% of available free cash. Available free cash is defined as net cash from operating activities less capital expenditure, acquisition expenditure, amounts reserved for capital expenditure and acquisition expenditure and amounts required for debt servicing. In circumstances where there is surplus available free cash, at the discretion of our Board of Directors and in light of business and market conditions, we may consider the potential for additional stockholder returns through special dividends and share buy-backs as part of its broader capital management strategy.

Summary Description of the Company’s Non-Stockholder Approved Equity Compensation Plans

The Company does not have any non-stockholder approved equity compensation plans.

Recent Sales of Unregistered Securities

Other than as previously disclosed in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K, we did not issue any shares of our common stock in a transaction that was not registered under the Securities Act during the year ended December 31, 2021.

Purchases of Equity Securities by the Issuer and Affiliated Purchases

We had no repurchases of equity securities for the three months ended December 31, 2021.

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ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of our Financial Condition and Results of Operations, or MD&A, should be read in conjunction with the Consolidated Financial Statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K.

Overview

For the year ended December 31, 2021, we produced 17.4 MMt and sold 17.8 MMt of coal. Met coal and thermal coal sales represented 81.4% and 18.6%, respectively, of our total volume of coal sold and 94.6% and 5.4%, respectively, of total coal revenues.

During the year ended December 31, 2021, seaborne prices reached record highs with both the Australian and U.S. coal price indices increasing largely as result of continued strong global steel demand and supply disruptions, mainly in in Australia, North America and China, caused by mine closures due to safety and environmental factors, labor shortages impacting production output and adverse weather conditions.

Coronado has continued to take advantage of its unique geographical diversification as a Met coal supplier of scale to meet the requirements of steel customers across the globe. While Chinese import restrictions on Australian coal persisted throughout 2021, our U.S. Operations benefited from their ability to export coal to China in a favorable pricing environment during the year ended December 31, 2021.

Our results of operations for the year ended December 31, 2021 benefited from higher averaged realized Met coal price, lower capital expenditure across our business and the continued ramp up of production at our U.S. Operations driven by increased demand from China for U.S. sourced metallurgical coals.

Despite these favorable conditions, our results for the year ended December 31, 2021, were adversely impacted by (1) temporary suspension of certain mining operations at Curragh following a tragic fatality in November 2021 which constrained production in the fourth quarter; (2) effects of La Nina weather pattern in Australia, which disrupted certain mining and logistics activities, (3) operational issues at the Australian Operations due to breakdown of certain mining equipment, (4) cost of additional fleets deployed at Curragh to accelerate overburden removal to increase coal availability, (5) labor shortages at Logan due to COVID-19 and (6) adverse geological conditions in certain mines of our U.S. Operations.

Coal revenues from our Australian Operations for the year ended December 31, 2021 increased 35.8% compared to the same period in 2020, driven by increased average realized Met coal pricing from $94.4 to $143.1 per Mt sold. Sales volumes were lower for the year ended December 31, 2021 compared to the same period in 2020 due to temporary suspension of certain mining operations following a safety incident in November 2021, equipment breakdown and seasonally higher wet weather conditions. Operating costs for the year ended December 31, 2021 were $126.2 million, or 12.8%, higher compared to the corresponding period in 2020 driven by higher mining costs (due to accelerated overburden removal), royalties and freight expenses, which together with lower coal sales volume, resulted in an unfavorable increase in operating costs of $18.6 per Mt sold.

From our U.S. Operations, production and sales volumes were 1.2MMt and 0.6Mt higher, respectively, for the year ended December 31, 2021 compared to the same period in 2020, primarily due to mining operations, returning to pre- COVID-19 levels. Higher sales volumes and higher average realized Met coal prices per Mt sold during the year ended December 31, 2021 resulted in Coal revenues increasing by $347.2 million, or 72.1%, compared to the corresponding period in 2020. Operating costs for the year ended December 31, 2021 were $120.4 million, or 29.8% higher, compared to the corresponding period in 2020 driven by higher mining and freight costs.

Refinancing transaction

During the year ended December 31, 2021, we successfully completed a refinancing initiative which comprised of the ABL Facility with an aggregate principal amount of $100.0 million, an offering of 10.750% senior secured notes due 2026, or the Notes, in an aggregate principal amount of $350.0 million and a fully underwritten equity entitlement offer of $101.4 million. These transactions provide Coronado increased financial flexibility by eliminating the application of the financial covenants under the prior syndicated facility agreement, or the SFA, and introducing new debt with terms that are more sustainable for our business.

Refer to Note 7 “Capital Structure” and Note 17 “Interest bearing liabilities” to the consolidated financial statements included in Part II, Item 8, of this Annual Report on Form 10-K.

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Notes Redemption

On November 16, 2021, we exercised our optional redemption rights and redeemed $35.0 million, or 10%, of the aggregate principal amount of our Notes at a redemption price equal to 103% of the principal amount of the Notes, plus accrued and unpaid interest on the Notes to, but not including, the date of redemption. We recorded a “Loss on debt extinguishment” of $2.8 million in the Consolidated Statement of Operations and Comprehensive Income, which represents the premium paid on redemption and a portion of unamortized debt issuance costs and discount on issuance.

Sale of Amonate Mining Asset

On December 2, 2021, we completed the sale of our Amonate mining asset to Ramaco Resources Inc. resulting in a pre-tax net realized gain of $14.8 million, comprised of sales proceeds of $30.0 million less carrying value of $12.6 million and transaction costs of $2.6 million, recorded within “Gain on disposal of assets” in our Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2021.

Xcoal

On May 27, 2021, Xcoal Energy and Resources, or Xcoal, ceased to be a related party under U.S. GAAP, after Xcoal’s founder, chief executive officer and chief marketing officer, Mr. Ernie Thrasher, retired as a non-executive director of the Company.

During the year ended December 31, 2021, Xcoal repaid its past due balance of $85.2 million from 2020 in full. At December 31, 2021, we fully reversed the provision for discounting and credit losses of $9.0 million recorded at December 31, 2020.

“Coal revenues from related parties” of $97.3 million in the Consolidated Statements of Operations and Comprehensive Income for the period up to May 27, 2021, represent revenues from Xcoal while it was a related party. Revenues from coal sales to Xcoal after May 27, 2021 of $137.1 million for the year ended December 31, 2021, are included within “Coal revenues” in the Consolidated Statements of Operations and Comprehensive Income.

From July 1, 2021, we agreed to credit terms with Xcoal. Any sales in excess of the credit amount will be made on prepayment, letter of credit and cash on delivery basis.

At December 31, 2021, amounts outstanding from Xcoal in respect of coal sales was $35.2 million, of which $17.9 million was past due, and is included within “Trade receivables, net” on the Consolidated Balance Sheet. Subsequent to December 31, 2021, the Company has collected the Xcoal’s past due balance in full. The carrying value of trade receivables from Xcoal at December 31, 2021, net of provision for credit losses of $0.4 million, was $34.8 million.

Safety

For our Australian Operations, the twelve-month rolling average TRIFR at December 31, 2021 was 3.07 compared to 9.40 at the end of December 31, 2020. At our U.S. Operations, the twelve-month rolling average TRIR, at December 31, 2021 was 2.51 compared to 2.28 at the end of December 31, 2020. Reportable rates for our Australian and U.S. Operations are below the relevant industry benchmarks.

The safety of our workforce is our number one priority and Coronado remains focused on the safety and wellbeing of all employees and contracting parties.

COVID-19 response

The COVID-19 Steering Committee has successfully monitored the effect of the pandemic across our Australian Operations, and U.S. Operations and continues to implement proactive preventative measures to ensure the safety and well-being of employees and contractors. During the year ended December 31, 2021, we implemented a Vaccine Incentive Program at our U.S. Operations that provides a cash payment to employees who get vaccinated. Since the program commenced, vaccination rates amongst our U.S. workforce have improved significantly. At our Australian Operations, vaccination rates continue to increase according to the Australian Federal and Queensland state government’s vaccination program, reaching 90% of the Queensland state population fully vaccinated. Our efforts are now firmly behind the encouragement of booster shots to ensure prolonged protection. The COVID-19 Steering Committee continues to execute action plans to manage the risks associated with COVID-19 variants.

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Segment Reporting

In accordance with Accounting Standards Codification, or ASC, 280, Segment Reporting, we have adopted the following reporting segments: Australia and the United States. In addition, “Other and Corporate” is not a reporting segment but is disclosed for the purposes of reconciliation to our consolidated financial statements.

Results of Operations

How We Evaluate Our Operations

We evaluate our operations based on the volume of coal we can safely produce and sell in compliance with regulatory standards, and the prices we receive for our coal. Our sales volume and sales prices are largely dependent upon the terms of our coal sales contracts, for which prices generally are set based on daily index averages, on a quarterly basis or annual fixed price contracts.

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability. These financial and operating metrics include: (i) safety and environmental metrics; (ii) total sales volumes and average realized price per Mt sold, which we define as total coal revenues divided by total sales volume; (iii) Met sales volumes and average realized Met price per Mt sold, which we define as Met coal revenues divided by Met sales volume; (iv) average segment mining costs per Mt sold, which we define as mining costs divided by sales volumes (excluding non-produced coal) for the respective segment; and (v) average segment operating costs per Mt sold, which we define as segment operating costs divided by sales volumes for the respective segment.

Coal revenues are shown on our statement of operations and comprehensive income exclusive of other revenues. Generally, export sale contracts for our Australian Operations require us to bear the cost of freight from our mines to the applicable outbound shipping port, while freight costs from the port to the end destination are typically borne by the customer. Sales to the export market from our U.S. Operations are generally recognized when title to the coal passes to the customer at the mine load out similar to a domestic sale. For our domestic sales, customers typically bear the cost of freight. As such, freight expenses are excluded from cost of coal revenues to allow for consistency and comparability in evaluating our operating performance.

Non-GAAP Financial Measures; Other Measures

The following discussion of our results includes references to and analysis of Adjusted EBITDA and mining costs, which are financial measures not recognized in accordance with U.S. GAAP. Non-GAAP financial measures, including Adjusted EBITDA, are used by investors to measure our operating performance.

Adjusted EBITDA, a non-GAAP measure, is defined as earnings before interest, tax, depreciation, depletion and amortization and other foreign exchange losses. Adjusted EBITDA is also adjusted for certain discrete non-recurring items that we exclude in analyzing each of our segments’ operating performance. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly titled measures presented by other companies. A reconciliation of Adjusted EBITDA to its most directly comparable measure under U.S. GAAP is included below.

Segment Adjusted EBITDA is defined as Adjusted EBITDA by operating and reporting segment, adjusted for certain transactions, eliminations or adjustments that our CODM does not consider for making decisions to allocate resources among segments or assessing segment performance. Segment Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements such as investors, industry analysts and lenders to assess the operating performance of the business.

Mining costs, a non-GAAP measure, is based on reported cost of coal revenues, which is shown on our statement of operations and comprehensive income exclusive of freight expense, Stanwell rebate, other royalties, depreciation, depletion and amortization and selling, general and administrative expenses, adjusted for other items that do not relate directly to the costs incurred to produce coal at mine. Mining costs excludes these cost components as our CODM does not view these costs as directly attributable to the production of coal. Mining costs is used as a supplemental financial measure by management, providing an accurate view of the costs directly attributable to the production of coal at our mining segments, and by external users of our financial statements, such as investors, industry analysts and ratings agencies, to assess our mine operating performance in comparison to the mine operating performance of other companies in the coal industry.

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Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Summary

The financial and operational highlights for the year ended December 31, 2021:

•Sales volume totaled 17.8 MMt for the year ended December 31, 2021, or 0.4 MMt lower than the year ended December 31, 2020. The lower sales volumes were attributable to our Australian Operations, primarily due to temporary suspension of operations following the fatality in November 2021, equipment breakdowns, wet weather conditions and labor shortage due to COVID-19.

•Net income increased by $416.0 million, from a net loss of $226.5 million for the year ended December 31, 2020, to a net income of $189.4 million for the year ended December 31, 2021. The higher net income was largely a result of higher coal sales revenues and the prior year including the impact of a non-cash impairment charge relating to Greenbrier, partially offset by higher operating costs, interest charges and income tax expense in 2021.

•Strong demand and higher prices in the seaborne Met coal market, especially in the second half of 2021 with coal index prices reaching record highs, caused by China's import policy decisions, post pandemic steel demand and impact of La Nina weather patterns, resulted in average realized Met pricing of $138.0 per Mt sold for the year ended December 31, 2021, or 52.5% higher compared to $90.5 per Mt sold for the year ended December 31, 2020.

•Adjusted EBITDA for the year ended December 31, 2021, totaled $486.1 million, an increase of $432.3 million, from Adjusted EBITDA of $53.8 million for the year ended December 31, 2020, driven by higher coal revenues partially offset by higher operating costs.

•Cash provided by operating activities was $442.0 million for the year ended December 31, 2021, an increase of $445.0 million compared to cash used of $3.0 million for the year ended December 31, 2020.

•As of December 31, 2021, the Company had total available liquidity of $537.7 million, consisting of $437.7 million of cash (excluding restricted cash) and $100 million of availability under the ABL Facility. The ABL Facility is subject to a springing fixed charge coverage ratio test if availability is less than a certain amount.

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