BTU US Equity☆

btu-20201231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

FORM 10-K

(Mark One)

For the Fiscal Year Ended December 31, 2020

or

Commission File Number 1-16463

____________________________________________

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

(Address of principal executive offices) (Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share BTU New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

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

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

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

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

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

Large accelerated filer ☐ Accelerated filer☑

Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of 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 ☑

Aggregate market value of the voting and non-voting common equity held by non-affiliates (stockholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2020: Common Stock, par value $0.01 per share, $196.3 million.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑No ☐

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 16, 2021: Common Stock, par value $0.01 per share, 98,244,140 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s 2021 Annual Meeting of Shareholders (the Company’s 2021 Proxy Statement) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We use words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond our control. Factors that could affect our results or an investment in our securities include, but are not limited to:

•our profitability depends upon the prices we receive for our coal;

•if a substantial number of our long-term coal supply agreements, including those with our largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts;

•risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us;

•our take-or-pay arrangements could unfavorably affect our profitability;

•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;

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

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

•our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal;

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

•we may be unable to obtain, renew or maintain permits necessary for our operations, or we may be unable to obtain, renew or maintain such permits without conditions on the manner in which we run our operations, which would reduce our production, cash flows and profitability;

•concerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have affected and could continue to affect demand for our products or our securities and our ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators;

•numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting our future financial results, liquidity and growth prospects;

•our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks;

•if the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated;

•our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable;

•we face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;

•joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards;

•we may undertake further repositioning plans that would require additional charges;

•our business, results of operations, financial condition and prospects could be materially and adversely affected by the recent coronavirus (COVID-19) pandemic and the related effects on public health;

Peabody Energy Corporation 2020 Form 10-K i

•our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect;

•we are subject to various general operating risks which may be fully or partially outside of our control;

•our financial performance could be adversely affected by our funded indebtedness (Indebtedness);

•despite our Indebtedness, we may still be able to incur more debt, which could further increase the risks associated with our Indebtedness;

•the terms of the indentures governing our senior secured notes and the agreements and instruments governing our other Indebtedness and surety bonding obligations impose restrictions that may limit our operating and financial flexibility;

•the number and quantity of viable financing and insurance alternatives available to us may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around our efforts with respect to environmental and social matters and related governance considerations could harm the perception of our company by a significant number of investors or result in the exclusion of our securities from consideration by those investors;

•the price of our securities may be volatile and could fall below the minimum allowed by New York Stock Exchange (NYSE) listing requirements;

•our common stock is subject to dilution and may be subject to further dilution in the future;

•there may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests;

•the payment of dividends on our stock or repurchase of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured;

•we may not be able to fully utilize our deferred tax assets;

•acquisitions and divestitures are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits;

•our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt;

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

•other risks and factors, including those discussed in “Legal Proceedings,” set forth in Part I, Item 3 of this report and “Risk Factors,” set forth in Part I, Item 1A of this report.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws.

Peabody Energy Corporation 2020 Form 10-K ii

TABLE OF CONTENTS

Page

PART I.

Item 1. Business 2

Item 1A. Risk Factors 26

Item 1B. Unresolved Staff Comments 39

Item 2. Properties 40

Item 3. Legal Proceedings 50

Item 4. Mine Safety Disclosures 50

PART II.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 84

Item 8. Financial Statements and Supplementary Data 86

Item 9A. Controls and Procedures 86

Item 9B. Other Information 89

PART III.

Item 10. Directors, Executive Officers and Corporate Governance 89

Item 11. Executive Compensation 89

Item 14. Principal Accountant Fees and Services 90

PART IV.

Item 15. Exhibits and Financial Statement Schedules 90

Signatures 98

Peabody Energy Corporation 2020 Form 10-K 1

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PART I

Item 1. Business.

Overview

We are a leading coal producer. At December 31, 2020, we owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia. Included in that count is our 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts through trading and business offices in the U.S., Australia, China and the United Kingdom.

Throughout the year ended December 31, 2020, we idled nine individual mines for periods ranging from one week to multiple months. Included in the count was our Shoal Creek Mine in Alabama, which was idled in October 2020 to reset the cost structure of the mine amid weak pricing and demand, and our Metropolitan Mine in New South Wales, Australia, which was idled in late December 2020.

As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020 and the first quarter of 2021, we entered into a series of interrelated agreements with our surety bond providers, the revolving lenders under our credit agreement and certain holders of our senior secured notes to extend a significant portion of our near-term debt maturities to December 2024 and to stabilize collateral requirements for our existing surety bond portfolio.

In December 2019, after receiving the requisite regulatory and permitting approvals, we formed an unincorporated joint venture with Glencore plc (Glencore), in which we hold a 50% interest, to combine the existing operations of our Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. Both parties contributed mining tenements upon formation of the joint venture (United Wambo Joint Venture), and the combined operations commenced in December 2020. As per the joint venture agreement, we fully owned and operated the Wambo Open-Cut Mine through the date combined operations commenced. At that date, the parties contributed mining equipment and other assets, and certain additional construction and development activities are ongoing. We proportionally consolidate the entity based upon our economic interest.

On April 13, 2016, Peabody and a majority of its wholly owned domestic subsidiaries, as well as one international subsidiary in Gibraltar (collectively with Peabody, the Debtors), filed voluntary petitions for reorganization under Chapter 11 of Title 11 of the U.S. Code in the U.S. Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Debtors’ Chapter 11 cases (collectively, the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.). On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763, confirming the Debtors’ Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan). On April 3, 2017, (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.

Segment and Geographic Information

As of December 31, 2020, we report our results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other. Refer to Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding our segments. Note 25. “Segment and Geographic Information” to the accompanying consolidated financial statements is incorporated herein by reference and also contains segment and geographic financial information.

Mining Locations

The maps that follow display our active mine locations as of December 31, 2020. Also shown are the primary ports that we use for our coal exports and our corporate headquarters in St. Louis, Missouri.

Peabody Energy Corporation 2020 Form 10-K 2

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U.S. Locations

Peabody Energy Corporation 2020 Form 10-K 3

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Australian Locations

Peabody Energy Corporation 2020 Form 10-K 4

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The table below summarizes information regarding the operating characteristics of each of our mines that were active in 2020 in the U.S. and Australia. The mines are listed within their respective mining segment in descending order, as determined by tons sold in 2020.

Seaborne Thermal Mining

Wilpinjong New South Wales S D, T/S T R, EV 13.8

Wambo Open-Cut (1) New South Wales S T/S T R, EV 4.0

Wambo Underground (2) New South Wales U LW T, C R, EV 1.2

Seaborne Metallurgical Mining

Coppabella (3) Queensland S DL, D, T/S P R, EV 2.0

Metropolitan (4) New South Wales U LW C, P, T R, EV 1.4

Moorvale (3) Queensland S D, T/S C, P, T R, EV 1.0

Shoal Creek (4) Alabama U LW C B, EV 0.9

Millennium (5) Queensland S HW C, P R, EV 0.3

Middlemount (6) Queensland S D, T/S C, P R, EV —

Powder River Basin Mining

North Antelope Rochelle Wyoming S D, DL, T/S T R 66.1

Caballo Wyoming S D, T/S T R 11.6

Rawhide Wyoming S D, T/S T R 9.5

Other U.S. Thermal Mining

Bear Run Indiana S DL, D, T/S T Tr, R 5.7

El Segundo/Lee Ranch New Mexico S D, DL, T/S T R 4.6

Wild Boar Indiana S D, T/S, HW T Tr, R, R/B, T/B 2.0

Gateway North Illinois U CM T Tr, R, R/B, T/B 1.9

Francisco Underground Indiana U CM T R 1.8

Twentymile Colorado U LW T R, Tr 1.6

Somerville Central (7) Indiana S DL, D, T/S T R, R/B, T/B, T/R 0.5

Wildcat Hills Underground (8) Illinois U CM T T/B 0.2

Legend:

S Surface Mine B Barge

U Underground Mine Tr Truck

HW Highwall Miner R/B Rail to Barge

DL Dragline T/B Truck to Barge

D Dozer/Casting T/R Truck to Rail

T/S Truck and Shovel EV Export Vessel

LW Longwall T Thermal/Steam

CM Continuous Miner C Coking

R Rail P Pulverized Coal Injection

(1)In December 2020, the United Wambo Joint Venture began joint production. The tons shown reflect our proportionate share throughout the year. The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest.

(2)Majority-owned mine in which there is an outside non-controlling ownership interest.

(3)We own a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. The tons shown reflect our share.

(4)Mine was idled during the fourth quarter of 2020.

(5)Mine ceased production in March 2020, with sales continuing throughout May 2020.

(6)We own a 50% equity interest in Middlemount, which owns the Middlemount Mine. Because that entity is accounted for as an unconsolidated equity affiliate, 2020 tons sold from that mine, which totaled 3.2 million tons (on a 100% basis), have been excluded from the table above.

(7)Mine ceased production in December 2020, with sales continuing into January 2021.

(8)Mine ceased production in December 2019, with sales continuing throughout April 2020.

Refer to the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table within Part I, Item 2. “Properties,” which is incorporated by reference herein, for additional information regarding coal reserves, product characteristics and production volume associated with each mine.

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Coal Supply Agreements

Customers. Our coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of our sales from our mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions). A smaller portion of our sales from our mining operations are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 89%, 88% and 87% of our worldwide sales from our mining operations (by volume) for the years ended December 31, 2020, 2019 and 2018, respectively. A recent trend has been for our customers under long-term coal supply agreements to seek contracts of shorter duration.

For the year ended December 31, 2020, we derived 32% of our revenues from coal supply agreements from our five largest customers. Those five customers were supplied primarily from 28 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2021 to 2026. Our largest customer in 2020 contributed revenue of approximately $264 million, or approximately 9% of our total revenues from coal supply agreements, and has contracts expiring at various times from 2021 to 2023.

Backlog. Our sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 264 million and 327 million tons of coal as of January 1, 2021 and 2020, respectively. Contracts in backlog have remaining terms ranging from one to six years and represent approximately two years of production based on our 2020 production volume of 128.8 million tons. Approximately 62% of our backlog is expected to be filled beyond 2021.

Seaborne Mining Operations. Revenues from our Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 42%, 45% and 48% of our total revenues from coal supply agreements for the years ended December 31, 2020, 2019 and 2018, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 19%, 17% and 16% of our sales volumes from mining operations. Our production is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Industry commercial practice, and our typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis. For our seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 39% in 2020.

U.S. Thermal Mining Operations. Revenues from our Powder River Basin Mining and Other U.S. Thermal Mining segments, in aggregate, represented approximately 58%, 55% and 52% of our revenues from coal supply agreements for the years ended December 31, 2020, 2019 and 2018, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 81%, 83% and 84% of our sales volumes from mining operations. We expect to continue selling a significant portion of coal production from our U.S. thermal mining segments under existing long-term supply agreements. Certain customers utilize long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements may vary in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Our approach is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices and terms and conditions we believe are favorable. However, recent trends indicate that customers may be less likely to enter into long-term supply agreements prospectively, driven by the reduced utilization of plants and plant retirements, sustained low natural gas pricing and the increased use of renewable energy sources.

Transportation

Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Our U.S. mine sites are typically adjacent to a rail loop; however, in limited circumstances coal may be trucked to a barge site or directly to customers. Title predominately passes to the purchaser at the rail or barge, as applicable. Our U.S. and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. In each case, we usually pay transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).

We believe we have good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.

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Export Facilities. We have generally secured our ability to transport coal in Australia through rail and port contracts and access to five east coast coal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on our take-or-pay obligations). In Queensland, seaborne thermal and metallurgical coal from our mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by our joint venture Middlemount Mine. In New South Wales, our primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group. We have secured our ability to transport coal from our Shoal Creek Mine under barge and port contracts; the primary port is the McDuffie Terminal in Mobile, Alabama, which we utilize without a take-or-pay arrangement.

Our U.S. thermal mining operations exported less than 1% and approximately 1% of its annual tons sold during the years ended December 31, 2019 and 2018, respectively. No tons were exported during the year ended December 31, 2020. The primary ports used for U.S. thermal exports are the United Bulk Terminal near New Orleans, Louisiana, the St. James Stevedoring Anchorages terminal in Convent, Louisiana and the Kinder Morgan terminal near Houston, Texas.

Suppliers

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

In situations where we have elected to concentrate a large portion of our purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts and ensure security of supply. Supplier concentration related to our mining equipment also allows us to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across our global platform, enhancing our flexibility to move equipment between mines and reduce working capital through inventory optimization.

Surface and underground mining equipment demand and lead times have remained steady in recent periods. We consistently use our global leverage with major suppliers to ensure security of supply to meet the requirements of our active mines.

Services. We also purchase services at our mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements. We do not believe that we have undue operational or financial risk associated with our dependence on any individual service providers.

Competition

Demand for coal and the prices that we will be able to obtain for our coal are highly competitive and influenced by factors beyond our control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative sources; the impact of weather on heating and cooling demand; taxes and environmental regulations imposed by the U.S. and foreign governments.

Thermal Coal

Demand for our thermal coal products is impacted by economic conditions; demand for electricity, which is impacted by energy efficient products; and the cost of electricity generation from coal and alternative forms of generation. Our products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use. The use and price of thermal coal is heavily influenced by the availability and relative cost of alternative fuel sources and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price. Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption.

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In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation. The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity, as well as comparatively low natural gas prices (versus historic levels). The Henry Hub Natural Gas Prompt Price averaged $2.13 per mmBtu in 2020, versus $2.53 and $3.07 per mmBtu in 2019 and 2018, respectively. The growth in domestic natural gas production and logistical constraints has led to discounts for regional gas prices versus the Henry Hub price, further driving lower natural gas price trends. In addition, the competitiveness of other alternative fuel sources for electricity generation has been strengthened by the growth of low-cost and government subsidized generation fueled by other alternative fuel sources. These pressures, coupled with increasing regulatory burdens, have contributed to a significant number of coal plant retirements. During 2020, approximately 11 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by more than thirty percent.

Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, among others.

In addition to our alternative fuel source competitors, our principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners, American Consolidated Natural Resources, Inc., Arch Resources, Inc., CONSOL Energy, Eagle Specialty Materials LLC, Foresight Energy, Hallador Energy, Kiewit, and Navajo Transitional Energy Company LLC, among others. Major international direct coal supply competitors (listed alphabetically) include Adaro Energy, Anglo American plc, BHP, Bumi Resources, China Shenhua Energy, Coal India Limited, Drummond Company, Glencore, South32, SUEK, Whitehaven Coal Limited and Yancoal Australia Ltd, among others.

Metallurgical Coal

Demand for our metallurgical coal products is impacted by economic conditions; government policies; demand for steel; and competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces. We compete on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, and the competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others.

Major international direct competitors (listed alphabetically) include Anglo American, Arch Resources, Inc., BHP, Glencore, Jellinbah, KRU, Shanxi Coking Coal Group, Teck Resources, Warrior Met Coal, Whitehaven Coal Limited and Yancoal Australia Ltd, among others.

Cybersecurity Risk Management

We use digital technology to conduct our business operations and engage with our customers, vendors and partners. As we implement newer technologies such as cloud, analytics, automation and “internet of things,” the threats to our business operations from cyber intrusions, denial of service attacks, manipulation and other cyber misconduct increase. To address the risk, we continue to evolve our risk management approach in an effort to continually assess and improve our cybersecurity risk detection, deterrence and recovery capabilities. Our cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of our cyber defense and resilience capabilities. These include: (i) proactive management of cyber risk to ensure compliance with contractual, legal and regulatory requirements, (ii) performing due diligence on third parties to ensure they have sound cybersecurity practices in place, (iii) ensuring essential business services remain available during a business disruption, (iv) implementing data policies and standards to protect sensitive company information and (v) exercising cyber incident response plans and risk mitigation strategies to address potential incidents should they occur. For more information regarding the risks associated with these matters, see “Item 1A. Risk Factors.”

Peabody Energy Corporation 2020 Form 10-K 8

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Human Capital

We had approximately 4,600 employees as of December 31, 2020, including approximately 3,500 hourly employees. Additional information on our employees and related labor relations matters is contained in Note 22. “Management — Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. During the year ended December 31, 2020, we reduced our global headcount by nearly 2,000 employees, in both operational and non-operational positions, representing approximately 30% of our workforce. The reductions were made in connection with our cost repositioning efforts to appropriately align our cost structure and optimize our coal production relative to prevailing market conditions.

As of December 31, 2020, approximately 2,900 of our employees are located in the U.S., with the remainder primarily located in Australia. About 92% of our team members work for mine operations in the U.S. and Australia, while the remaining are employed at our global headquarters in St. Louis or other business offices.

We strive to create a strong, united workforce with a commitment to safety as a way of life. In 2020, we achieved a global safety incidence rate of 1.67 incidents per 200,000 hours worked, which was 43% better than the 2019 U.S. industry average incidence rate of 2.93 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).

We offer an inclusive work environment and engage, recognize and develop employees. We seek a workforce that is comprised of diverse backgrounds, thoughts and experiences. Our company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. We believe in fostering an inclusive work environment built on mutual trust, respect and engagement. We invest in our employees through health and wellness programs, competitive total rewards and development opportunities.

The typical Peabody employee has approximately nine years of experience with the company, and more than 60% of all Peabody employees remain employed with the company for more than five years. We offer a variety of learning events, including mentoring and development programs to aid our employees in their career growth. During the past five years, approximately 36% of open positions and 70% of director and above positions have been filled by internal candidates through promotions and lateral career development opportunities.

Information About Our Executive Officers

Set forth below are the names, ages and positions of our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.

Name Age (1) Position (1)

Glenn L. Kellow 53 President and Chief Executive Officer

Mark A. Spurbeck 47 Executive Vice President and Chief Financial Officer

Scott T. Jarboe 47 Chief Legal Officer and Corporate Secretary

Darren R. Yeates 60 Executive Vice President and Chief Operating Officer

Paul V. Richard 61 Senior Vice President and Chief Human Resources Officer

Marc E. Hathhorn 50 President - Australian Operations

Kemal Williamson 61 President - U.S. Operations

(1) As of February 16, 2021.

Glenn L. Kellow was named our President and Chief Operating Officer in August 2013; our President, Chief Executive Officer-elect and a director in January 2015; and our President and Chief Executive Officer in May 2015. Mr. Kellow’s career experience enables him to provide the Company with valuable insights from miner, competitor fuel and industrial customer perspectives. From 1985 to 2013, he worked for BHP Ltd. in the United States, Australia and South America. Mr. Kellow has held chief executive leadership, operating and financial roles in global business in the coal, copper, nickel, aluminum, steel, oil and gas sectors. He serves as a Vice Chairman of the U.S. National Mining Association and a director and former Chairman of the World Coal Association. Mr. Kellow is a graduate of the Advanced Management Program at the University of Pennsylvania’s Wharton School of Business and holds a Master of Business Administration Degree and a Bachelor’s Degree in Commerce from the University of Newcastle. He also holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.

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Mark A. Spurbeck was named our Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020. He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions and investor relations and corporate communications. Mr. Spurbeck has more than 25 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer from early 2018 to January 2020. Prior to joining Peabody, Mr. Spurbeck served as Vice President of Finance and Chief Accounting Officer at Coeur Mining, Inc., a diversified precious metals producer, from March 2013 to January 2018. He also previously held multiple financial positions at Newmont Mining Corporation, a leading gold and copper producer, First Data Corporation, a financial services company, and Deloitte LLP, an international accounting, tax and advisory firm. Mr. Spurbeck is a Certified Public Accountant and holds a Bachelor’s Degree in Accounting from Hillsdale College.

Scott T. Jarboe was named our Chief Legal Officer and Corporate Secretary in March 2020. In this role, he has executive responsibility for providing comprehensive legal counsel for Peabody’s business activities and leads the Company’s global legal and compliance functions. Mr. Jarboe joined Peabody in 2010 and has served in a variety of legal roles. He most recently led the Litigation, Disputes and Labor & Employment activities for Peabody. Prior to joining Peabody, Mr. Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP. Mr. Jarboe holds a Bachelor of Arts Degree from the University of Kansas, a Master’s Degree from the University of Missouri – Kansas City and a Juris Doctor degree from Washington University School of Law.

Darren R. Yeates was named our Executive Vice President and Chief Operating Officer in October 2020. He has executive responsibility for operations, sales and marketing and technical services. Mr. Yeates has over 35 years of mining industry experience. From May 2018 to December 2019, Mr. Yeates served as Chief Operating Officer of MACH Energy Australia, a developer and supplier of thermal coal to both the Australian domestic and Asian export markets. From January 2014 until June 2016, Mr. Yeates served as the Chief Executive Officer of GVK Hancock Coal, a joint venture developing the vast potential of the Galilee Basin in Central Queensland. Prior to that, he spent over 22 years with Rio Tinto, a global mining group, including as Acting Managing Director and Chief Operating Officer for Coal Australia, General Manager Ports and Infrastructure for Pilbara Iron and General Manager Tarong Coal. Prior to joining Rio Tinto, Mr. Yeates worked for six years for BHP, a mining, metals and petroleum company, in coal operations and metalliferous exploration. Mr. Yeates has a Bachelor of Engineering (Mining) from the University of Queensland, a Graduate Diploma in Management from the University of Central Queensland and a Graduate Diploma of Applied Finance and Investment from the Securities Institute of Australia. He has an Executive MBA from the Monash Mt Eliza Business School and is a Fellow of the Australian Institute of Company Directors.

Paul V. Richard was named our Senior Vice President and Chief Human Resources Officer in November 2017. He has executive responsibility for organizational and employee development, benefits, compensation, international human resources, security, travel and facilities management. Mr. Richard has more than 30 years of human resources experience and has been instrumental in leading his prior organizations to achieve Great Place to Work and Top Training Organization designations. From 2002 to May 2017, Mr. Richard served as Vice President - Human Resources for Shaw Industries Group, Inc., a leading flooring materials producer and a subsidiary of Berkshire Hathaway, Inc. Prior to that, he served as a human resources leader for 19 years at Ferro Corporation, a global supplier of technology-based manufacturing, including four years as Vice President - Human Resources. Mr. Richard holds a Bachelor of Science Degree in Management and a Masters of Business Administration Degree from Louisiana Tech University.

Marc E. Hathhorn was named our President - Australian Operations in August 2019. He has executive responsibility for our Australian operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America. Mr. Hathhorn joined us in 2011 as our Senior Vice President - Midwest Operations, and subsequently served as our Group Executive - Americas Operations Support from 2013 to 2016, and Group Executive - Americas Operations from 2016 until assuming his current role. Previously, Mr. Hathhorn held various leadership positions with Drummond LTD in South America, including Mine Operations Superintendent, Port Manager, and Vice President - Mining Operations. Prior to joining Drummond LTD, Mr. Hathhorn held various engineering and supervisory positions with Newmont Gold Corporation. Mr. Hathhorn holds a Bachelor of Science Degree in Mining Engineering from the University of Idaho, College of Mines.

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Kemal Williamson was named our President - Americas in October 2012 and his title was updated to President - U.S. Operations in June 2019. He has executive responsibility for our U.S. operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Williamson has more than 30 years of experience in mining engineering and operations roles across North America and Australia. He most recently served as Group Executive of Operations for the Peabody Energy Australia operations. He also has held executive leadership roles across project development, as well as in positions overseeing our Powder River Basin and Other U.S. Thermal operations. Mr. Williamson joined us in 2000 as Director of Land Management. Prior to that, he served for two years at Cyprus Australia Coal Corporation as Director of Operations and managed coal operations in Australia for half a decade. He also has mining engineering, financial analysis and management experience across Colorado, Kentucky and Illinois. Mr. Williamson holds a Bachelor of Science Degree in Mining Engineering from Pennsylvania State University as well as a Master of Business Administration Degree from the Kellogg School of Management, Northwestern University in Evanston, Illinois.

Regulatory Matters — U.S.

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, 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. We believe that we have obtained all permits currently required to conduct our present mining operations.

We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry.

Mine Safety and Health

We are subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.

The MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.

In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on MSHA compliance.

Black Lung (Coal Workers’ Pneumoconiosis)

Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants 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. 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 Affordable Care Act. The trust fund has been funded by an excise tax on U.S. production. In 2008, the excise tax rates were set through December 31, 2018 at $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. On January 1, 2019 the rate reverted back to $0.50 per ton of underground coal and $0.25 per ton of surface coal, not to exceed 2% of the gross sales price. In December of 2019, legislation was passed that increased the rate for the year ending December 31, 2020. The enacted legislation mandates the previous rates of $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

We recognized expense related to the tax of $53.3 million, $31.4 million and $78.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.

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The Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes 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.

Environmental Laws and Regulations

We are subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance. We are also affected by various other federal, state, local and tribal environmental laws and regulations that impact our customers.

Temporary Enforcement Policy. On March 26, 2020, the United States Environmental Protection Agency (EPA) announced a temporary policy regarding EPA enforcement of environmental legal obligations as a result of the COVID-19 pandemic. (COVID-19 Implications for EPA’s Enforcement and Compliance Assurance Program). Under the temporary policy, the EPA exercised enforcement discretion for certain noncompliance events that occurred during the period of time that the temporary policy was in effect and that resulted from the COVID-19 pandemic. The EPA’s temporary policy did not provide leniency for intentional criminal violations of law and imposed conditions on any violation that may result in “acute risk or an imminent threat to human health or the environment.” The policy also did not apply to activities that were carried out under Superfund and Resource Conservation and Recovery Act (RCRA) Corrective Action enforcement instruments. The EPA's temporary policy became effective on March 13, 2020 and remained in effect until August 31, 2020.

Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSMRE), established mining, environmental protection and reclamation standards for surface mining and underground mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSMRE or from the respective state regulatory authority. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority, with oversight from OSMRE. States in which we have active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, where we will be performing reclamation work on tribal lands, we are regulated by the OSMRE because the tribes do not have SMCRA authorization.

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.

Our total reclamation bonding requirements in the U.S. were $1,139.3 million as of December 31, 2020. The bond requirements for a mine represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period. The cost calculation for each bond must be completed according to the regulatory authority of each state or OSMRE. Our asset retirement obligations calculated in accordance with generally accepted accounting principles for our U.S. operations were $502.8 million as of December 31, 2020. The bond requirement amount for our U.S. operations significantly exceeds the financial liability for final mine reclamation because the asset retirement obligation liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition that the final reclamation cash outlay is projected to be a number of years away. The bond amount, in contrast with the asset retirement obligation, presumes reclamation begins immediately, as well as different assumptions related to the cost of equipment and services utilized in the reclamation process.

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. 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.

In situations where our coal resources are federally owned, the U.S. Bureau of Land Management oversees a substantive exploration and leasing process. If surface land is managed by the U.S. Forest Service, that agency serves as the cooperating agency during the federal coal leasing process. Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.

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The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. 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 $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. We recognized expense related to the fees of $28.4 million, $36.5 million and $40.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our 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 (PM), nitrogen dioxide, ozone and sulfur dioxide (SO2). In recent years, the EPA has adopted more stringent national ambient air quality standards (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, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle and/or engine emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.

In 2009, the EPA adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. 74 Fed. Reg. 51,950 (Oct. 8, 2009). The PM NAAQS was thereafter revised and made more stringent in 2012. In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 parts per billion (ppb). (80 Fed. Reg. 65,292 (Oct. 25, 2015)). The primary ozone standard was upheld by the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in Murray Energy v. EPA, (D.C. Cir. 2019), Slip Op. 15-1385. The court, however, remanded the secondary ozone NAAQS standard to the EPA and vacated a “grandfathering” provision concerning the use of the prior ozone NAAQS in certain permitting actions.

The Clean Air Act requires the EPA to review NAAQS every five years to determine whether revision to current standards are appropriate. 42 U.S.C. §7409(d). As part of this recurring review process, the EPA proposed to retain the ozone standards promulgated in 2015, including current secondary standards. 85 Fed. Reg. 49,830 (Aug. 14, 2020).

The EPA also proposed to retain the PM standards promulgated in 2012 (85 Fed. Reg. 24,094 (Apr. 30, 2020)). On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. On December 31, 2020, the EPA issued a final rule to retain the current primary and secondary ozone standards. 85 Fed. Reg. 87,256 (Dec. 31, 2020).

More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxide and SO2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQS for SO2 of 75 ppb averaged over an hour.

The CAA also indirectly, but significantly, affects the U.S. coal industry by extensively regulating the air emissions of SO2, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.

In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed. At present, however, the EPA does not directly regulate such emissions.

Final NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). The EPA promulgated a final rule to limit carbon dioxide (CO2) from new, modified and reconstructed fossil fuel-fired EGUs under Section 111(b) of the CAA on August 3, 2015, and published it in the Federal Register on October 23, 2015.

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This rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb carbon dioxide per megawatt-hour gross output (CO2/MWh-gross). The standard (known as the Best System of Emission Reduction (BSER)) is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross).

Numerous legal challenges to the final rule were filed in the D.C. Circuit. Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial carbon capture and storage to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of carbon capture and storage technology. Status reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the proposed rule. On January 13, 2021, the EPA promulgated a final rule which did not address BSER, but rather finalized a pollutant-specific significant contribution determination for greenhouse gas emissions from EGUs of 3%. Thus, the NSPS remains in effect. (86 Fed. Reg. 2,542 (Jan. 13, 2021)).

EPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired EGUs. On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired EGUs under Section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).

Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the D.C. Circuit. The petitions reflected challenges by 27 states and governmental entities, as well as by utilities, industry groups, trade associations, coal companies and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states also joined) (D.C. Cir. No. 15-1363). On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states. The motion was granted on January 11, 2016. Numerous states and other entities also intervened in support of the EPA.

On February 9, 2016, the U.S. Supreme Court granted a motion to stay implementation of the CPP until the legal challenges were resolved. Thereafter, oral arguments in the case were heard in the D.C. Circuit sitting en banc. On April 28, 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the agency reconsidered the rule.

In October 2017, the EPA proposed to repeal the CPP. (82 Fed. Reg. 48,035 (Oct. 16, 2017)). In August 2018, the EPA issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule. (83 Fed. Reg. 44,746 (August 31, 2018)). On June 19, 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. (Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations, 84 Fed. Reg. 32,520 (July 8, 2019)). The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the BSER. The EPA’s final rule also revises the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans.

Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including Peabody, filed a motion to dismiss, which the court granted in September 2019.

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Numerous petitions for review challenging the ACE Rule were filed in the D.C. Circuit and consolidated in American Lung Association v. EPA (No. 19-1140 (D.C. Cir.)). This litigation has been fully briefed and oral argument before a 3-judge panel of the D.C. Circuit was held on October 8, 2020. The oral argument was organized around four issue areas concerning the EPA’s repeal of the CPP, the EPA’s authority to regulate power plants under the CAA, whether the ACE rule properly interpreted and applied the CAA and the treatment of biomass in the ACE Rule. On January 19, 2021, the panel held that the ACE Rule and its repeal of the CPP were to be vacated and remanded to the EPA. It also vacated amendments to the implementing regulations that extended the compliance timeline.

EPA’s Greenhouse Gas Permitting Regulations for Major Emission Sources. In May 2010, the EPA published final rules requiring permitting and control technology requirements for greenhouse gases under the Prevention of Significant Deterioration (PSD) and Title V permitting programs that apply to stationary sources of air pollution. The EPA determined that these requirements were “triggered” by the EPA’s prior regulation of greenhouse gases from motor vehicles. These rules were subsequently upheld by the D.C. Circuit on June 26, 2012. On June 23, 2014, however, the U.S. Supreme Court ruled that the EPA could not require PSD and Title V permitting for greenhouse gases emitted from stationary sources if those sources were not otherwise considered to be “major sources” of conventional pollutants for purposes of PSD and Title V (known as Step 2 sources). In accordance with that decision, the D.C. Circuit vacated the federal regulations that implemented Step 2 of the Greenhouse Gas Tailoring Rule in 2015. Subsequently, the EPA removed the vacated elements from its rules to ensure that neither the PSD nor Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit greenhouse gases above the applicable thresholds. The EPA therefore no longer has the authority to conduct PSD permitting for Step 2 sources, nor can the EPA approve provisions submitted by a state for inclusion in its state implementation plan providing this authority.

Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. On July 6, 2011, the EPA finalized the CSAPR, which 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 other 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. The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO2 (82 Fed. Reg. 45,481 (Sept. 29, 2017)).

On October 26, 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 ozone NAAQS. This rule imposed reductions in nitrogen oxides emissions beginning in 2017 in 22 states subject to CSAPR. Several states and utilities, as well as agricultural and industry groups, filed petitions for review of the CSAPR Update Rule in the D.C. Circuit. Wisconsin v. EPA, No. 16-1406. On September 13, 2019, the D.C. Circuit held that the CSAPR Update Rule did not comply with provisions of the Clean Air Act requiring upwind states to address air pollution which significantly interferes with the ability of a downwind state or states to attain NAAQS by relevant compliance dates. The court thus remanded the CSAPR Update Rule to the EPA in order for the Agency to address the court’s decision.

In 2018, the EPA issued another determination that the existing CSAPR Update Rule fully addressed the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 NAAQS for ground-level ozone. (83 Fed. Reg. 65,878 (Dec. 21, 2018)). This determination was also challenged in the D.C. Circuit (No. 19-1019). On October 1, 2019, the D.C. Circuit issued a judgment vacating this rule on the basis of the court’s decision in Wisconsin v. EPA. Additional litigation concerning the interstate transport of air pollution and the EPA’s response under the Clean Air Act continues. In Maryland v. EPA (No. 18-1285), the D.C. Circuit upheld EPA determinations that upwind states had not met their burden in seeking relief from transported air pollution under the same Clean Air Act provisions at issue in Wisconsin. In New York v. EPA, No. 19-1231 (D.C. Cir., July 14, 2020), the D.C. Circuit vacated the EPA’s denial of a Clean Air Act section 126 petition requesting that the Agency find approximately 350 sources of nitrogen oxides in nine States were contributing significantly to nonattainment in the New York Metropolitan Area. The court remanded the denial to the EPA for further proceedings consistent with the court’s opinion.

EPA has proposed a rule to address the court’s remand in Wisconsin as well as NOx emissions in 21 states targeted by the CSAPR Update Rule. 85 Fed. Reg. 68,964 (Oct. 30, 2020). The proposed rule would find that 9 of the states identified do not significantly contribute to downwind nonattainment and/or maintenance issues and therefore do not need additional emission reductions. For the 12 other states, EPA has proposed to adjust state NOx budgets downward and create a new emission trading program.

Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the NSPS for nitrogen oxides, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric 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.

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Following issuance of the final rule, numerous petitions for review were filed. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs against all challenges on April 15, 2014, in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. On June 29, 2015 the U.S. Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from power plants. The court reversed the D.C. Circuit and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision the EPA published a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.

On April 14, 2016, the EPA issued a final supplemental finding that largely tracked its proposed finding. Several states, companies and industry groups challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated (D.C. Cir. No. 116-1127). Several states and environmental groups also filed as intervenors for the respondent EPA. Although briefing in this litigation has concluded, the case remains in abeyance.

On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule that would revoke the determination that regulating HAPs from coal-fired power plants is “appropriate and necessary” under Section 112(n)(1)(A) of the CAA. The proposed finding was based on an EPA assessment that health and environmental benefits from the MATS rule were not directly related to mercury pollution and should not be included in the benefit portion of the analysis. A final rule reversing EPA’s 2016 Supplemental Finding and determining, in lieu, that it is not “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants was promulgated in May 2020. 85 Fed. Reg. 31,286 (May 22, 2020). This rule also finalized residual risk and technology review standards for the coal- and oil-fired EGU source category. Both actions have been challenged in the D.C. Circuit. See American Academy of Pediatrics et al. v. Wheeler, No. 20-1221 (D.C. Cir.), Air Alliance Houston, et al v. EPA, No. 20-1268 (D.C. Cir.).

Federal Coal Leasing Moratorium. President Trump’s Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in April 2019, the Court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the Court held that the Department of the Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations. Environmental groups have since amended their complaint to challenge the Environmental Assessment and FONSI, and the litigation remains pending.

Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.

The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain permits from the Corps to place material in or mine through jurisdictional waters of the U.S.

States are empowered to develop and apply water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Standards vary from state to state. Additionally, through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters. State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity. On June 1, 2020, the EPA issued a final rule intended to clarify the scope of the state or tribal regulators’ authority that could in effect limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances.

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New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the Clean Air Act’s PSD and Nonattainment New Source Review programs, generally referred to as NSR. On March 25, 2020, the EPA released a draft guidance document that would allow power plants, refineries and other sources of emissions to begin certain construction activities while still awaiting a permit under the NSR program. Under the EPA’s revised interpretation, a source owner or operator may, prior to obtaining a NSR permit, undertake physical on-site activities, including activities that may significantly alter the site and/or are permanent in nature, provided that those activities do not constitute physical construction on an emissions unit. The comment period on the draft memo ended May 11, 2020. On August 4, 2020, the EPA released a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the New Source Review Regulations). PALs allow sources to make physical and operational changes under a plantwide emission limit without “triggering” NSR.

The EPA has also taken action on a number of different rules and guidance affecting the interpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA completed reconsideration of a 2009 petition to clarify when certain actions must be “aggregated” for purposes of determining whether these actions are part of a single project to which NSR applies. The EPA has additionally published guidance on the definition of “ambient air” (Revised Policy on Exclusions from “Ambient Air,” Dec. 2, 2019) and guidance concerning when multiple air pollution-emitting activities may be considered to be “adjacent” so that they should be considered to be a single source (Interpreting “Adjacent” for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas, Nov. 26, 2019). Additional memorandum and applicability determinations have also been made that address other NSR issues. These rules, guidance and memorandum may therefore affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.

CWA Definition of “Waters of the United States”. A final rule defining the scope of waters protected under the CWA (commonly called the Waters of the United States, or WOTUS) (WOTUS Rule), was published by the EPA and the Corps in June 2015. Several states and others subsequently filed lawsuits challenging the 2015 WOTUS Rule, and eventually that rule was preliminarily enjoined in over half of the country. On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the 2015 WOTUS Rule and recodifying the regulatory definitions of WOTUS that existed prior to the implementation of the WOTUS Rule. On January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule to revise the definition of “Waters of the United States” and thereby establish the scope of federal regulatory authority under the CWA. A federal district judge in Colorado preliminarily enjoined the Navigable Waters Protection Rule in the State of Colorado on June 19, 2020. The new rule took effect in all other states on June 22, 2020, but the pre-2015 definitions apply in Colorado. Litigation over both the 2019 repeal rule and the 2020 Navigable Waters Protection Rule remains pending in several federal district courts.

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. The EPA has not yet determined how to address the vacated portions of the 2015 rule following the Fifth Circuit’s decision. Separately, on October 13, 2020, the EPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. As finalized, the revised effluent limitations guidelines could significantly increase costs for many coal-fired steam electric power plants.

National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. The final rule seeks to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule.

Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.

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Subtitle C of 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 coal combustion residuals (CCR or coal ash). 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. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.

Proposed Rule for Disposal of CCR from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country, and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. The EPA expects to issue a final rule around May 2021. Separately, on August 28, 2020, the EPA finalized certain amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision, and the EPA expects to issue a proposed rule in the summer of 2021. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.

Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA’s Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.

Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. 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 Department of the Interior issued three proposed rules in 2018 aiming to streamline and update the ESA. The three final rules became effective on September 26, 2019 and are currently the subject of a pending legal challenge filed in the U.S. District Court for the Northern District of California by a coalition of 18 states.

Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule. On July 30, 2019, the OSMRE officially withdrew its decision to initiate rulemaking related to emissions generated from blasting at coal mining operations. The decision cited its lack of statutory authority and the sufficiency of the existing regulatory framework.

Federal Report on Climate Change. On November 23, 2018, the U.S. Global Change Research Program, a working group comprised of 13 U.S. governmental departments and agencies, issued the Fourth National Climate Assessment. The report lists the observed effects of “increasing greenhouse gas concentrations on Earth’s climate” and enumerates the impacts of those observed effects. The report also discusses the alternatives for reducing the impacts of climate-related risks, including through mitigation and adaptation. While there are no explicit regulatory actions that flow from the issuance of the report, both the legislative and executive branches of government may rely on its conclusions to shape and justify policies and actions going forward. A Fifth National Climate Assessment is currently in development with an anticipated publication date in 2023.

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Regulatory Matters — Australia

The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.

Native Title and Cultural Heritage. Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry. The Inquiry’s terms of reference include reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. The Inquiry was due to finalize its report by December 9, 2020. The reporting deadline for the final report has been extended to October 2021 and instead the Joint Standing Committee released its interim report in December 2020. The interim report focused specifically on Western Australia but the next phase of the Inquiry will be expanded to encompass other Australian states and territories, both with a view to address particular issues and to develop a nationally consistent response to heritage protection. The Inquiry’s findings and resultant legislation, if any, could potentially impact the Company’s mining permits or existing mine plans in an effort to mitigate against adverse impacts to such sites.

Mining Tenements and Environmental. In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required. The environmental impacts of mining projects are regulated by state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (for example, a water resource, an endangered species or particular protected places). Environmental approvals processes involve complex issues that, on occasion, require lengthy studies and documentation.

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In February 2019, the New South Wales (NSW) Land and Environment Court (LEC) upheld the government’s denial of a planning approval for a non-Peabody coal mining project (Gloucester Resources Limited v. Minister for Planning). Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ greenhouse gas emissions resulting from the consumption of coal to be mined under the proposed project. Such emissions are often raised as a ground of objection to Australian mining projects, including our mining projects. For example, in a subsequent LEC decision (Australian Coal Alliance Incorporated v. Wyong Coal Pty Ltd), the approval of a coal mining project was confirmed after such emissions had been considered by the relevant authority. In August 2019, Peabody and Glencore received approval from the NSW Independent Planning Commission (IPC) for the United Wambo project, subject to conditions (Export Conditions) requiring the joint venture to prepare an Export Management Plan setting out protocols for using all reasonable and feasible measures to ensure that any coal extracted from the mine that is to be exported from Australia is only exported to countries that are parties to the Paris Agreement (as defined below) or countries that the NSW Planning Secretary considers to have similar policies for reducing greenhouse gas emissions. The IPC subsequently approved another non-Peabody coal mining project (Rix’s Creek) without any Export Conditions. In October 2019, the NSW government introduced into Parliament proposed amendments to legislation and policy that would, if passed, have the effect of invalidating Export Conditions imposed on future NSW planning approvals, as well as no longer requiring consent authorities to consider ‘downstream emissions’ when assessing developments for the purposes of mining, petroleum production or extractive industry. The NSW government has announced changes to the IPC and planning system process which aims to improve timeframes and efficiencies for project approvals and providing more clarity on the IPC’s role in determining applications including seeking guidance on government policy. In June 2020, the NSW Government released its Strategic Statement on Coal Exploration and Mining in NSW which provides a high level framework for the government's policy approach to the future of the coal sector, as well as details of a streamlined strategic release process. The strategy identifies some potential areas for possible new coal exploration, areas that are ruled out for coal mining and areas where new coal exploration can only occur adjacent to an existing coal title via the Operational Allocation process. In December 2020, the NSW Government finalized and published the Guideline for the Competitive Allocation of Coal, which details the process for considering areas for coal exploration and allocating them by public tender.

In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959. Under the EP Act, policies have been developed to achieve the objectives of the law and provide guidance on specific areas of the environment, including air, noise, water and waste management. State planning policies address matters of Queensland state interest, and must be adhered to during mining project approvals. The Mineral Resources Act 1989 was amended effective September 27, 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land. In November 2016, amendments to the EP Act and the Water Act 2000 became effective that facilitate regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction. The ‘chain of responsibility’ provisions of the EP Act, which became effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances: (a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later); or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company). A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.

In New South Wales, laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 2012, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks & Wildlife Act 1974.

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Under the EPA Act, environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve.

On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied.

Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state-specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. Self-bonding is not permitted. Our mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements. This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under our credit facility and accounts receivable securitization program. We operate in both the Queensland and New South Wales state jurisdictions.

Our reclamation bonding requirements in Australia were $312.6 million as of December 31, 2020. The bond requirements represent the calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The costs associated with our Australian asset retirement obligations are calculated in accordance with generally accepted accounting principles and were $225.4 million as of December 31, 2020. The total bonding requirements for our Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.

New South Wales Reclamation. The Mining Act 1992 (Mining Act) is administered by the Department of Planning and Environment and the New South Wales Resources Regulator, and authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other auxiliary approvals and licenses.

Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a mining operations plan (MOP) prior to the commencement of operations. All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change. The mines publicly report their reclamation performance on an annual basis.

In support of the MOP process, a reclamation cost estimate is calculated periodically to determine the amount of bond support required to cover the cost of reclamation based on the extent of disturbance during the MOP period.

Under significant reforms proposed by the NSW Resources Regulator in October 2020, all new and existing mines in NSW will be regulated by new standard rehabilitation conditions. The conditions will apply to all new and existing mining leases and focus on transparently requiring progressive mine site rehabilitation throughout the life of the mine. The draft Mining Amendment (Standard Conditions of Mining Leases - Rehabilitation) Regulation 2020 has been released for consultation. The new conditions would apply to all new mining leases and would be introduced into existing mining leases over a 12 to 24 month transition period. The conditions require (amongst other things) that the leaseholder must rehabilitate land and water in the mining area that is disturbed by activities under the mining lease as soon as reasonably practicable after the disturbance occurs. The proposed rehabilitation management plan for the mining area which must be prepared for large mines is intended to replace the current approach of preparing a mining operation plan.

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Queensland Reclamation. The EP Act is administered by the Department of Environment and Science, which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA. All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA. The mines submit an annual return reporting on their EA compliance.

In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 providing for a new financial assurance (FA) framework and new progressive rehabilitation requirements. The new FA framework creates a pooled fund covering most mines and most of the total industry liability, plus other options for providing FA if not part of the pooled fund (for example, allowing insurance bonds or cash). The percentage rate of the total rehabilitation cost payable into the pooled fund will take into account the financial strength of the holder of the EA for the mine and the project strength of the mine. The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which no longer provides for discounting. The commencement date for the new FA framework was April 1, 2019 and there is a transitional period during which we will move each of our mines in Queensland into the new FA framework.

The new progressive rehabilitation requirements commenced on November 1, 2019 and require each mine, within a three-year transitional period, to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation will require regulatory approval. If there is to remain an area within the mine that does not have a post-mining land use (referred to as a non-use management area or NUMA) then each such NUMA will need to pass a public interest evaluation test as part of the approval process. An example of a NUMA is the void that remains after open-cut mining activities have been completed. Under the legislation, each current mine is exempt from the requirement to justify its NUMAs to the extent that its current approvals provide for such areas. We are of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of our Queensland mines.

Residual Risks. On August 20, 2020, the Environmental Protection and Other Legislation Amendment Act (Queensland) 2020 (EPOLA Act) became law amending the residual risk framework that aims to ensure that any remaining risks on former resource sites are appropriately identified, costed and managed. On completion of all mining activities, the holder of the EA for the mine can apply to surrender the EA once all conditions, requirements and rehabilitation obligations have been met. When approving the surrender, the government can request a residual risk payment from the holder of the EA for the mine to cover potential rehabilitation or maintenance costs incurred after the surrender has been accepted. It contemplates two approaches for determining residual risk payments. Depending on the level of risk of a particular site, a cost calculator tool might be used or a panel of appropriately qualified experts might undertake a qualitative and quantitative risk assessment.

Federal Reclamation. In February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999. The Committee released their report in March 2019. The Committee was unable to reach unanimous agreement on a set of recommendations. It is unclear the extent to which the report will impact policy reform at a federal government level.

Occupational Health and Safety. State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.

In September 2020, Safe Work Australia (SWA) published its revised Workplace Exposure Standards (WES) for coal dust and silica based on toxicological information and other monitoring data. SWA have recommended exposure limits of 1.5 mg/m3 for coal dust (to apply from October 2022) and 0.05 mg/m3 for silica (to apply as soon as possible). In Queensland, the new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m3)) took effect from July 1, 2020. In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m3 commenced on July 1, 2020. The respirable coal dust workplace exposure standard of 2.5 mg/m3 will be reduced to 1.5 mg/m3 commencing on February 1, 2021 and mines will need to report exceedances of the new exposure standard to the NSW Resources Regulator from this commencement date. NSW will be the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard of 0.1 mg/m3 to also commence on February 1, 2021

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On July 1, 2020, the Resources Safety and Health Queensland Act 2020 became effective. It establishes Resources Safety and Health Queensland (RSHQ) as a statutory body designed to ensure independence of the mining safety and health regulator. RSHQ includes inspectorates for coal mines, mineral mines and quarries, explosives and petroleum and gas. The new law seeks to enhance the role of advisory committees to identify, quantify and prioritize safety and health issues in the mining and quarrying industries. It also provides for an independent Work Health and Safety Prosecutor to prosecute serious offenses under resources safety legislation.

On May 20, 2020, the Queensland Parliament passed a bill into law that introduces the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are “senior officers” and companies in the mining industry. Individuals now face a maximum prison sentence of 20 years and companies could be fined up to approximately $13 million Australian dollars. This new law became effective July 1, 2020. The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity with an 18-month transition period ending November 25, 2021.

Industrial Relations. A national industrial relations system, the Fair Work Act and National Employment Standards, administered by the federal government applies to all employers and employees. The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes. Most of the hourly workers employed in our mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.

National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas 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 NGER Act. The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review.

On July 1, 2016, amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions at or below the baseline or face penalties.

The National Greenhouse and Energy Reporting Rule 2015 outlines key elements of a responsible emitter’s duty to avoid an excess emissions situation and provides detail on how it can meet that requirement. The rule was amended in March 2019 with the effect that all current reported covered emissions baselines will expire on June 30, 2020, and there will be alternatives for setting new baselines, including by reference to default emissions intensity values.

Queensland Royalty. As part of the Queensland Government’s 2019-20 Budget, the Government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contribute to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The Government contributes $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the Fund was approximately $713,000 Australian dollars for the 2019-20 financial year and is expected to decrease in years two and three based on an expected reduction in production at our Queensland mines.

New South Wales Royalty. In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines.

Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning, Industry and Environment (DPIE) on the impact of underground mining activities in Sydney’s water catchment areas, including at our Metropolitan Mine. The Panel issued its final report in October 2019. The final report makes findings and recommendations concerning mining activities and effects across the catchment as a whole.

The DPIE considered the recommendations in the Panel’s final report and in April 2020 announced that it had accepted all 50 recommendations in the Panel’s report, and that it has established an interagency taskforce to implement a detailed action plan during 2020. The action plan includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new independent expert panel to advise on future mining applications in the catchment; strengthening surface and groundwater monitoring; improving access to and transparency of environmental data; adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts; reviewing and updating current and potential future water losses from mining in line with the best available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine closure planning to reduce potential long-term impacts.

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Global Climate

In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no such legislation has been signed into law. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA has taken steps to regulate greenhouse gas emissions pursuant to the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” In particular, in 2015, the EPA announced final rules (known as the CPP) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. Twenty-seven states and governmental entities, as well as utilities, industry groups, trade associations, coal companies (including Peabody), and other entities, challenged the CPP in federal court. Implementation of the CPP was stayed by the U.S. Supreme Court pending resolution of its legal challenges. In October 2017, the EPA proposed to change its legal interpretation of section 111(d) of the CAA, the authority that the agency relied on for the original CPP. The EPA relied on the proposed reinterpretation until August 2018, when it proposed the Affordable Clean Energy Rule (the ACE Rule) to replace the CPP with a system where states would develop emissions reduction plans using BSER measures (essentially efficiency heat rate improvements), and the EPA would approve the state plans if they use EPA-approved candidate technologies. Changes in the NSR program were also proposed to allow efficiency improvements to be made without triggering NSR requirements. In September 2019, the ACE Rule, which provides states with the flexibility to regulate on a plant-by-plant basis with a focus on coal-fired EGUs, became effective and the CPP was repealed. Proposed revisions to the regulations under the NSR program that were part of the ACE proposal were separated and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date. Following the effectiveness of the ACE Rule, the case challenging the CPP in federal court was dismissed as being moot. On January 19, 2021, the D.C. Circuit Court of Appeals held that the ACE Rule and its repeal of the CPP were to be vacated and remanded to the EPA. It also vacated amendments to the implementing regulations that extended the compliance timeline.

At the same time, a number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six mid-western states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.

Several other U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.

Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.

We participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and we regularly disclose in our annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by us in the U.S. The vast majority of our emissions are generated by the operation of heavy machinery to extract and transport material at our mines and fugitive emissions from the extraction of coal.

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The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reductions contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global greenhouse gas emissions. On January 20, 2021, the U.S. reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement in November 2019.

In October 2017, the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meets Australia’s international commitments to emissions reduction. The plan was referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework. The NEG was abandoned by the Australian government in September 2018. Following the outcome of the federal election in May 2019, the federal government confirmed it will not revive the former NEG policy. Instead, the government will pursue a new energy and climate change policy, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions. The Climate Solutions Fund is an extension of the former Emissions Reduction Fund. The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.

The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on us of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. From time to time, we attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on our operations, financial condition or cash flow. We do not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on our results of operations, financial condition or cash flows.

Available Information

We file or furnish annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC. These materials are available free of charge through our website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on our website does not constitute part of this document. These materials may also be accessed through the SEC’s website (www.sec.gov).

In addition, copies of our filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.

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Item 1A. Risk Factors.

We operate in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect our business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business.

Risks Associated with Our Operations

Our profitability depends upon the prices we receive for our coal.

We operate in a competitive and highly regulated industry that has experienced strong headwinds. Depressed coal prices have reduced our revenues, and sustained prices at current levels or further declines in coal prices will adversely affect our operating results and financial condition. Further declines in coal prices will adversely affect the value of our coal reserves.

Coal prices are dependent upon factors beyond our control, including:

•the demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal);

•changes in the fuel consumption and dispatch patterns of electric power generators, whether based on economic or non-economic factors;

•the proximity, capacity and cost of transportation and terminal facilities;

•competition with and the availability, quality and price of coal and alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;

•governmental regulations and taxes, including tariffs or other trade restrictions as well as those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable energy sources;

•the strength of the global economy;

•the global supply and production costs of thermal and metallurgical coal;

•the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of our metallurgical coal contracts;

•weather patterns, severe weather and natural disasters;

•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases; and

•technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.

Thermal coal accounted for the majority of our coal sales by volume during 2020 and 2019. The vast majority of our sales of thermal coal were to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear fuel, oil and alternative energy sources; (iii) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulations; and (v) the coal inventories of utilities. Gas-fueled generation has displaced and is expected to continue to displace coal-fueled generation (particularly from older, less efficient coal-fueled generation units) as current and potentially increasing regulatory costs and other factors impact the operating decisions of electric power generators. In addition, some electric power generators have made decisions to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many of the new power plants in the U.S. may be fueled by natural gas because gas-fired plants have been less expensive to construct, permits to construct these plants are easier to obtain based on emissions profiles, and electric power generators may face public and governmental pressure to generate a larger portion of their electricity from natural gas-fueled units and alternative energy sources. Increasingly stringent regulations along with stagnant electricity demand have also reduced the number of new power plants being built. These trends have reduced demand for our coal and the related prices. Any further reduction in the amount of coal consumed by electric power generators could reduce the volume and price of coal that we mine and sell.

We produce metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 17% and 22% of our revenues in 2020 and 2019, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for our metallurgical coal. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

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The balance between coal demand and supply, factoring in demand and supply of closely related and competing segments such as natural gas, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenues and profitability. We compete with other fuel sources used for electricity generation, such as natural gas and renewables. Our seaborne products compete with other producers as well as other fuel sources. Declines in the price of natural gas could cause demand for coal to decrease and adversely affect the price of coal. Sustained periods of low natural gas prices or low prices for other fuels may also cause utilities to phase out or close existing coal-fueled power plants or reduce construction of new coal-fueled power plants. In the U.S., no new coal-fueled power plants are being constructed or reopened after closure. These closures could have a material adverse effect on demand and prices for our coal, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

If a substantial number of our long-term coal supply agreements, including those with our largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.

Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2020, we derived 32% of our revenues from coal supply agreements from our five largest customers. Those five customers were supplied primarily from 28 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2021 to 2026.

Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We may experience reductions in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Some coal supply agreements allow customers to vary the volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that we amend the agreements to allow for such variation. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.

On an ongoing basis, we discuss the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term supply agreements.

The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase our exposure to short-term coal price volatility. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, our revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.

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Risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us.

Our mining operations are subject to conditions that can impact the safety of our workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:

•elevated gas levels;

•fires and explosions, including from methane gas or coal dust;

•accidental mine water discharges;

•weather, flooding and natural disasters;

•hazardous events such as roof falls and high wall or tailings dam failures;

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

•key equipment failures;

•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits, and geologic conditions impacting mine sequencing;

•delays in moving our longwall equipment;

•unexpected maintenance problems; and

•unforeseen delays in implementation of mining technologies that are new to our operations.

We maintain insurance policies that provide limited coverage for some of the risks referenced above, which may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under our insurance policies in connection with losses associated with these risks.

Our take-or-pay arrangements could unfavorably affect our profitability.

We have substantial take-or-pay arrangements, predominately in Australia, totaling $1.2 billion, with terms ranging up to 22 years, that commit us to pay a minimum amount for rail and port commitments for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow us to apply amounts paid for subsequent deliveries, but these provisions have limitations and we may not be able to apply all such amounts so paid in all cases. Also, we may not be able to utilize the amount of capacity for which we have previously paid. Additionally, we may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.

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.

The value of our assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract our coal reserves; and unanticipated increases in operating costs. During the years ended December 31, 2020 and 2019, the Company recorded $1,487.4 million and $270.2 million of impairment charges related to such factors, as further described in Note 3. “Asset Impairment” to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.

Because of the volatile and cyclical nature of coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for adjustments to the carrying value of our assets.

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

As of December 31, 2020, we had approximately 4,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 3,500 hourly employees. We are party to labor agreements with various labor unions that represent certain of our employees. Such labor agreements are negotiated periodically, and, therefore, we are subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 29% of our hourly employees were represented by organized labor unions and generated approximately 18% of our coal production for the year ended December 31, 2020. Relations with our employees and, where applicable, organized labor are important to our success. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations or successfully negotiate contracts with our employees who are represented by unions, we could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact our profitability.

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

U.S. federal and state laws and Australian 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 are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2020, we had $1,633.6 million of outstanding surety bonds and $437.6 million of letters of credit with third parties in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees.

Our financial assurance obligations may increase or become more costly due to a number of factors, and surety bonds and letters of credit may not be available to us, particularly in light of some banks and insurance companies’ announced unwillingness to support thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where our mines reside. Our failure to retain, or inability to obtain, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could have a material adverse effect on us. That failure could result from a variety of factors including the following:

•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit; and

•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit.

As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company reached a surety transaction support agreement with the providers of 99% of its surety bond portfolio to resolve approximately $800 million in additional collateral demands made by the sureties. The sureties have agreed to a standstill through December 31, 2024, during which time, the sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves, or cancel any existing surety bond. Our failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect our business and results of operations.

Our failure to maintain adequate bonding would invalidate our mining permits and prevent mining operations from continuing, which could result in our inability to continue as a going concern.

Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.

The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:

•workplace health and safety;

•limitations on land use;

•mine permitting and licensing requirements;

•reclamation and restoration of mining properties after mining is completed;

•the storage, treatment and disposal of wastes;

•remediation of contaminated soil, sediment and groundwater;

•air quality standards;

•water pollution;

•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;

•protection of wetlands;

•the discharge of materials into the environment; and

•the effects of mining on surface water and groundwater quality and availability.