PEABODY ENERGY CORP 10-K

btu-20201231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _____________________________________________ FORM 10-K (Mark One) ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31 , 2020 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-16463 ____________________________________________ PEABODY ENERGY CORP ORATION (Exact name of registrant as specified in its charter) Delaware 13-4004153 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 701 Market Street, St. Louis, Missouri 63101-1826 (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 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 51 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 53 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 84 Item 8. Financial Statements and Supplementary Data 86 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 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 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 89 Item 13. Certain Relationships and Related Transactions, and Director Independence 89 Item 14. Principal Accountant Fees and Services 90 PART IV. Item 15. Exhibits and Financial Statement Schedules 90 Item 16. Form 10-K Summary 97 Signatures 98 Peabody Energy Corporation 2020 Form 10-K 1 Table of Contents Note: The words “we,” “us,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Annual Report on Form 10-K relate only to our continuing operations. When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms). 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 Table of Contents U.S. Locations Peabody Energy Corporation 2020 Form 10-K 3 Table of Contents Australian Locations Peabody Energy Corporation 2020 Form 10-K 4 Table of Contents 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. Segment/Mining Complex Location Mine Type Mining Method Coal Type Primary Transport Method 2020 Tons Sold (In millions) 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. Peabody Energy Corporation 2020 Form 10-K 5 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 6 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 7 Table of Contents 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 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 9 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 10 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 11 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 12 Table of Contents 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 (SO 2 ). In recent years, the EPA has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO 2 . 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 (PM 2.5 ) and the primary 24-hour standard for coarse particulate matter (PM 10 ) and secondary PM 10 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 SO 2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQS for SO 2 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 SO 2 , 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 (CO 2 ) 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. Peabody Energy Corporation 2020 Form 10-K 13 Table of Contents 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 (CO 2 /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 CO 2 /MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO 2 /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. Peabody Energy Corporation 2020 Form 10-K 14 Table of Contents 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 SO 2 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 SO 2 (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, SO 2 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. Peabody Energy Corporation 2020 Form 10-K 15 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 16 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 17 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 18 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 19 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 20 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 21 Table of Contents 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/m 3 for coal dust (to apply from October 2022) and 0.05 mg/m 3 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/m 3 )) took effect from July 1, 2020. In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m 3 commenced on July 1, 2020. The respirable coal dust workplace exposure standard of 2.5 mg/m 3 will be reduced to 1.5 mg/m 3 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/m 3 to also commence on February 1, 2021 Peabody Energy Corporation 2020 Form 10-K 22 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 23 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 24 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 25 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 26 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 27 Table of Contents 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. Peabody Energy Corporation 2020 Form 10-K 28 Table of Contents 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. Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of our mines, our production and sale of coal would be disrupted and we may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on our financial condition, results of operations and cash flows. Peabody Energy Corporation 2020 Form 10-K 29 Table of Contents New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure or our customers’ ability to use coal. New legislation or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of greenhouse gas emissions that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Some of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations. For additional information about the various regulations affecting us, see the sections entitled “Regulatory Matters —U.S.” and “Regulatory Matters — Australia.” 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. Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including in the U.S., CERCLA and RCRA, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved. 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. Numerous governmental and tribal permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when we apply for permits and approvals, we are required to prepare and present to governmental authorities data pertaining to the potential impact or effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups. Additionally, our operations may be affected by sites within or near mining areas deemed to have cultural heritage significance to indigenous peoples, and our mining permits may be rescinded or modified, or our mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites. The costs, liabilities and requirements associated with these permitting requirements and any related opposition may be extensive and time-consuming and may delay commencement or continuation of exploration or production which would adversely affect our coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially 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. Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants. Peabody Energy Corporation 2020 Form 10-K 30 Table of Contents The enactment of future laws, the passage of regulations, or other executive orders 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 mines or coal-fueled power stations could adversely impact the global supply and demand for coal. 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. Similarly, 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 some 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 flows. 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. 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. Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation in the U.S. and across the globe. In an effort to stop or delay coal mining activities, activist groups have brought lawsuits challenging the issuance of individual coal leases, and challenging the federal coal leasing program more broadly. Other lawsuits challenge historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities in the past have reached private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking. The effect of these and other similar developments has made it more costly and difficult to maintain our business. These cost increases and/or substantial or extended declines in the prices we receive for our coal due to these or other factors could reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and could result in material losses. Our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks. In addition to coal price volatility, we are currently subject to price volatility on diesel fuel utilized in our mining operations and the Australian dollar. We may in the future enter into hedging arrangements to manage these risks, or other exposures. Some of these hedging instruments may require us to post margin based on the value of those instruments and other credit factors. If the fair value of our hedge portfolio moves significantly, or if laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could negatively impact our liquidity. Peabody Energy Corporation 2020 Form 10-K 31 Table of Contents 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 asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. Our management and engineers periodically review these estimates. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition. Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable. Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Moreover, the amount of proven and probable coal reserves described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenues and expenditures with respect to our coal reserves may vary materially from estimates. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2020, we leased a total of 44,645 acres from the federal government subject to those limitations. Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, in order to develop our reserves, we must also own the rights to the related surface property and receive various governmental permits. We cannot predict whether we will continue to receive the permits or appropriate land access necessary for us to operate profitably in the future. We may not be able to negotiate or secure new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders. In addition, from time to time, our permit applications and federal and state coal leases have been challenged, causing production delays. To the extent that our existing sources of liquidity are not sufficient to fund our planned mine development projects and reserve acquisition activities, we may require access to capital markets, which may not be available to us or, if available, may not be available on satisfactory terms. If we are unable to fund these activities, we may not be able to maintain or increase our existing production rates and we could be forced to change our business strategy, which could have a material adverse effect on our financial condition, results of operations and cash flows. Peabody Energy Corporation 2020 Form 10-K 32 Table of Contents 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. Coal is economically recoverable when the price at which our coal can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which our coal is economically recoverable varies based on the mine. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff and third parties, which includes various engineers and geologists. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include: • geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience in areas we currently mine; • demand for coal; • current and future market prices for coal, contractual arrangements, operating costs and capital expenditures; • severance and excise taxes, royalties and development and reclamation costs; • future mining technology improvements; • the effects of regulation by governmental agencies; • the ability to obtain, maintain and renew all required permits; • employee health and safety; and • historical production from the area compared with production from other producing areas. As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially and adversely affect our business, results of operations, financial position and cash flows. Additionally, our reserve estimates may be adversely affected in the future by the SEC’s recent rule amendments revising property disclosure requirements for publicly-traded mining companies. We will be required to comply with these new rules in 2021. Joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards. We participate in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact our results of operations and our liquidity or impair our ability to recover our investments. Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational standards. We also utilize contractors across our mining platform, and may be similarly limited in our ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to ours could unfavorably affect safety results, operating costs and productivity and adversely impact our results of operations and reputation. We may undertake further repositioning plans that would require additional charges. As a result of our continuing review of our business or changing demand, we may choose to further modify our portfolio of operations and/or reduce our workforce in the future. These actions may result in further restructuring charges, cash expenditures and the consumption of management resources, any of which could cause our operating results to decline and may fail to yield the expected benefits. Peabody Energy Corporation 2020 Form 10-K 33 Table of Contents Our business, results of operations, financial condition and prospects could be materially and adversely affected by the recent COVID-19 pandemic and the related effects on public health. Our operations are susceptible to widespread outbreaks of illness or other public health issues, such as the continuing global COVID-19 pandemic. The COVID-19 pandemic could have a material adverse effect on our business, results of operations, financial condition and prospects, including our ability to comply with covenants under our debt agreements. The COVID-19 pandemic has caused governments around the world, including in the U.S. and Australia, to implement quarantines, travel bans and shutdowns, which have significantly restricted the movement of people and goods. The continuing spread of COVID-19 has contributed to adverse changes in general domestic and global economic conditions and disrupted domestic and international credit markets. Within the global coal industry, supply and demand disruptions resulting from the COVID-19 pandemic have been widespread and have adversely impacted us and our customers, as further described in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Governmental mandates, and our efforts to act in the best interests of our employees, customers, suppliers, vendors and joint venture and other business partners, have affected and are continuing to affect our business and operations, causing us to modify a number of our normal business practices. Additional governmental mandates could require forced shutdowns of our mines and other facilities for extended or indefinite periods and widespread outbreaks in locations significant to our operations could adversely affect our workforce, resulting in serious health issues and absenteeism. In addition, the COVID-19 pandemic may cause supply chains and distribution channels to be interrupted, slowed or rendered inoperable. If our operations are curtailed, we may need to seek alternate sources of supply for commodities, services and labor, which may be more expensive. Alternate sources may not be available or may result in delays in shipments to our customers. Further, if our customers’ businesses are similarly affected, they might delay, reduce or cancel purchases from us. Adverse changes in the general domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect our customers’ ability to pay us as well as our ability to access capital that could negatively affect our liquidity. Despite our efforts to manage these realized and potential impacts, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of the COVID-19 pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may further negatively affect both demand and prices for our products. We also face disruption to supply chain and distribution channels, potentially increasing costs of production, storage and distribution, and potential adverse effects to our workforce, each of which could have a material adverse effect on our business, financial condition, results of operations and prospects. Our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect. We pay postretirement health and life insurance benefits to eligible retirees. Our total accumulated postretirement benefit obligation related to such benefits was a liability of $442.9 million as of December 31, 2020, of which $29.7 million was classified as a current liability. These liabilities are actuarially determined. We use various actuarial assumptions, including the discount rate, future cost trends, mortality tables and rates of return on plan assets to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. A decrease in the discount rate used to determine our postretirement benefit and defined benefit pension obligations could result in an increase in the valuation of these obligations, thereby increasing the cost in subsequent fiscal years. We have made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase our obligation to satisfy these or additional obligations. We develop our actuarial determinations of liabilities using actuarial mortality tables we believe best fit our population’s actual results. In deciding which mortality tables to use, we periodically review our population’s actual mortality experience and evaluate results against our current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee in order to select mortality tables for use in our year end valuations. If our mortality tables do not anticipate our population’s mortality experience as accurately as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Additionally, our reported defined benefit pension funding status may be affected, and we may be required to increase employer contributions, due to increases in our defined benefit pension obligation or poor financial performance in asset markets in future years. Peabody Energy Corporation 2020 Form 10-K 34 Table of Contents Our defined benefit pension plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). It is implicit in our underlying assumptions that those plans continue to operate in the normal course of business. However, the Pension Benefit Guaranty Corporation (PBGC) may terminate our plans under certain circumstances pursuant to ERISA, including in the event that the PBGC concludes that its risk may increase unreasonably if such plans continue to operate based on its assessment of the plans’ funded status, our financial condition or other factors. Termination of the plans would require us to provide immediate funding or other financial assurance to the PBGC for all or a substantial portion of the underfunded amounts, as determined by the PBGC based on its own assumptions. Those assumptions may differ from our own. Any of those consequences could have a material adverse effect on our results of operations, financial conditions or available liquidity. We are subject to various general operating risks which may be fully or partially outside of our control. Our results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may be fully or partially outside of our control. Such risks stem from internal and external sources and include: • global economic recessions and/or credit market disruptions; • deterioration of the creditworthiness of our customers or counterparties to financial instruments, and their ability to perform under contracts; • inability of suppliers and other counterparties, including those related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the terms of their contracts with us; • decreases in the availability or increases in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires; • disruption to, or increased costs within, the transportation chain for coal, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels; • failure to attract and retain skilled and qualified personnel, particularly as the prevalence of coal-fired electricity generation declines; • new or increased forms of taxation imposed by federal, state, provincial or local governmental authorities, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes; • uncertainties associated with our global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates; and • cyber-attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our employees, our customers or other third-parties. Risks Related to Our Indebtedness and Capital Structure Our financial performance could be adversely affected by our Indebtedness. As of December 31, 2020, we had approximately $1.5 billion of Indebtedness outstanding, excluding finance leases and debt issuance costs. 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,” in January 2021 we entered into a series of interrelated transactions 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. While our aggregate amount of Indebtedness did not materially change as a result of these transactions, our incremental cost of borrowing and cash paid for interest expenses will increase prospectively. Peabody Energy Corporation 2020 Form 10-K 35 Table of Contents The degree to which we are leveraged could have important consequences, including, but not limited to: • making it more difficult for us to pay interest and satisfy our debt obligations; • increasing the cost of borrowing; • increasing our vulnerability to general adverse economic and industry or regulatory conditions; • requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our Indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements; • limiting our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements; • limiting our ability to refinance or otherwise exchange existing debt at commercially acceptable rates; • making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing, particularly during periods in which credit markets are weak; • limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; • causing a decline in our credit ratings; and • placing us at a competitive disadvantage compared to less leveraged competitors. In addition, our Indebtedness subjects us to certain restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us and result in amounts outstanding thereunder to be immediately due and payable. The terms of our Indebtedness provide that if we cannot meet our debt service obligations, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. A downgrade in our credit ratings or other unfavorable indicators could result in, among other matters, a requirement to post additional collateral on derivative trading instruments that we may enter into, the loss of trading counterparties for corporate hedging and trading and brokerage activities or an increase in the cost of, or a limit on our access to, various forms of credit used in operating our business. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our Indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our Indebtedness may restrict the use of the proceeds from any such sales. We may not be able to complete those sales and the proceeds may not be adequate to meet any debt service obligations then due. Despite our Indebtedness, we may still be able to incur more debt, which could further increase the risks associated with our Indebtedness. We may be able to incur additional Indebtedness in the future. Although covenants under the indentures governing our senior secured notes and the agreements governing our other Indebtedness, including our credit facility, revolver and finance leases, limit our ability to incur additional Indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, debt incurred in compliance with these restrictions can be material. In addition, the indenture governing the senior secured notes and the agreements governing our other Indebtedness do not limit us from incurring obligations that do not constitute Indebtedness as defined therein. 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 indentures governing our senior secured notes and the agreements governing our other Indebtedness and surety bonding obligations contain certain restrictions and covenants which restrict our ability to incur liens and/or debt or provide guarantees in respect of obligations of any other person and other restrictions, all of which could adversely affect our ability to operate our business, as well as significantly affect our liquidity, and therefore could adversely affect our results of operations. Peabody Energy Corporation 2020 Form 10-K 36 Table of Contents These covenants limit, among other things, our ability to: • incur additional Indebtedness; • pay dividends on or make distributions in respect of stock or make certain other restricted payments, such as share repurchases; • make capital investments; • enter into agreements that restrict distributions from certain subsidiaries; • sell or otherwise dispose of assets; • use for general purposes the cash received from certain allowable asset sales or disposals; • enter into transactions with affiliates; • create or incur liens; • merge, consolidate or sell all or substantially all of our assets; and • receive dividends or other payments from subsidiaries in certain cases. Our ability to comply with these covenants may be affected by events beyond our control and we may need to refinance existing debt in the future. A breach of any of these covenants together with the expiration of any cure period, if applicable, could result in a default under our senior secured notes. If any such default occurs, subject to applicable grace periods, the holders of our senior secured notes may elect to declare all outstanding senior secured notes, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If the obligations under our senior secured notes were to be accelerated, our financial resources may be insufficient to repay the notes and any other Indebtedness becoming due in full. In addition, if we breach the covenants in the indentures governing the senior secured notes and do not cure such breach within the applicable time periods specified therein, we would cause an event of default under the indenture governing the senior secured notes and a cross-default to certain of our other Indebtedness and the lenders or holders thereunder could accelerate their obligations. If our Indebtedness is accelerated, we may not be able to repay our Indebtedness or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our Indebtedness is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions. 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. Certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coverage for the development of new coal-fueled power plants and coal producers and utilities that derive a majority of their revenue from coal, and particularly from thermal coal. This may adversely impact the future global demand for coal. Increasingly, the actions of such financial institutions and insurance companies are informed by non-standardized “sustainability” scores, ratings and benchmarking studies provided by various organizations that assess environmental, social and governance matters. Further, there have been efforts in recent years by members of the general financial and investment communities, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, or that have low ratings or scores in studies and assessments of the type noted above, including coal producers. These entities also have been pressuring lenders to limit financing available to such companies. These efforts may have adverse consequences, including, but not limited to: • restricting our ability to access capital and financial markets in the future; • reducing the demand and price for our equity securities; • increasing the cost of borrowing; • causing a decline in our credit ratings; • reducing the availability, and/or increasing the cost of, third-party insurance; • increasing our retention of risk through self-insurance; • making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and • limiting our flexibility in business development activities such as mergers, acquisitions and divestitures. Peabody Energy Corporation 2020 Form 10-K 37 Table of Contents Risks Related to Ownership of Our Securities The price of our securities may be volatile and could fall below the minimum allowed by New York Stock Exchange (NYSE) listing requirements. The price of our common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of our Common Stock regardless of our operating performance, including, among others: • actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in our industry; • industry cycles and trends; • mergers and strategic alliances in the coal industry; • changes in government regulation; • potential or actual military conflicts or acts of terrorism; • the failure of securities analysts to publish research about us or to accurately predict the results we actually achieve; • changes in accounting principles; • announcements concerning us or our competitors; • the purchase and sale of shares of our Common Stock by significant shareholders; • lack of trading liquidity; and • the general volatility of securities markets. As a result of all of these factors, investors in our Common Stock may not be able to resell their stock at or above the price they paid or at all. In the recent past, our closing stock price has fallen below $1.00 per share for a limited number of trading days. If our stock were to trade below $1.00 per share for 30 consecutive trading days, NYSE could commence suspension and delisting procedures. Further, we could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on our results of operation. Our Common Stock is subject to dilution and may be subject to further dilution in the future. Our Common Stock is subject to dilution from our long-term incentive plan. In addition, in the future, we may issue equity securities in connection with future investments, acquisitions or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding Common Stock, which may result in significant dilution in ownership of Common Stock. There may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests. Circumstances may arise in which the interests of a significant stockholder may be in conflict with the interests of our other stakeholders. A significant stockholder may exert substantial influence over us to cause us to take action that aligns with their interests, for example, to pursue or prevent acquisitions, divestitures or other transactions, including the issuance or repurchase of additional shares or debt, that, in its judgment, could enhance its investment in us or another company in which it invests. Such transactions may advance the interests of the significant stockholder and not necessarily those of other stakeholders, which might adversely affect us or other holders of our Common Stock or debt instruments. The payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured. 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, we entered into transaction support agreements with our surety bond providers which prohibit the payment of dividends on our stock or repurchases of our stock through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to pay cash dividends and repurchase shares. Such restrictions may negatively impact the trading price of the Common Stock. The payment of future cash dividends and future repurchases will depend upon these restrictions, as well as our earnings, economic conditions, liquidity and capital requirements, and other factors, including our leverage and other financial ratios. Accordingly, we cannot make any assurance that future dividends will be paid or future repurchases will be made. Peabody Energy Corporation 2020 Form 10-K 38 Table of Contents General Business Risks We may not be able to fully utilize our deferred tax assets. We are subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2020, we had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $2,311.6 million and $54.4 million, respectively, as described further in Note 10. “Income Taxes” to the accompanying consolidated financial statements. At that date, we also had recorded a valuation allowance of $2,287.3 million. The Company’s ability to use its NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 (Section 382) of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change. Although we may be able to utilize some or all of those deferred tax assets in the future if we have income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that we will be able to do so. Further, we are presently unable to record tax benefits on future losses in the U.S. and Australia until such time as sufficient income is generated by our operations in those jurisdictions to support the realization of the related net deferred tax asset positions. Our results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations. 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. We may engage in acquisition or divestiture activity based on our set of investment criteria to produce outcomes that increase shareholder value or provide potential strategic benefits. If we fail to accurately estimate the future results and value of an acquired or divested business or assets and the related risk associated with such a transaction, or are unable to successfully integrate the businesses or assets we acquire, our business, financial condition or results of operations could be negatively affected. Moreover, any transactions we pursue could materially impact our liquidity and an acquisition could increase capital resource needs and may require us to incur Indebtedness, seek equity capital or both. We may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions. Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt. Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Common Stock and may have the effect of delaying or preventing a change in control. Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results. The mining industry has limited industry-specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of our significant accounting policies. Item 1B. Unresolved Staff Comments. None. Peabody Energy Corporation 2020 Form 10-K 39 Table of Contents Item 2. Properties. Coal Reserves We controlled an estimated 3.0 billion tons of proven and probable coal reserves as of December 31, 2020. An estimated 2.6 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 2% of our U.S. proven and probable coal reserves, or 52 million tons, are metallurgical coking coal. The remainder of our U.S. coal reserves consists of thermal coal. Approximately 56% of our Australian proven and probable coal reserves, or 243 million tons, are metallurgical coal, comprised of approximately 121 million and 122 million tons of coking coal and low-volatile pulverized coal injection (LV PCI) coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. We own approximately 6% of these reserves and leased property comprises the remaining 94%. Approximately 88% of our reserves, or 2.7 billion tons, are compliance coal and 12% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal. Below is a table summarizing the locations and proven and probable coal reserves of our major mining segments. Proven and Probable Reserves as of December 31, 2020 (1) Owned Tons Leased Tons Total Tons Mining Segment Locations (Tons in millions) Seaborne Thermal Mining New South Wales — 211 211 Seaborne Metallurgical Mining Queensland, New South Wales and Alabama — 275 275 Powder River Basin Mining Wyoming — 2,223 2,223 Other U.S. Thermal Mining Illinois, Indiana, Kentucky, New Mexico and Colorado 190 149 339 Total Proven and Probable Coal Reserves 190 2,858 3,048 Total United States 190 2,424 2,614 Total Australia — 434 434 Total Proven and Probable Coal Reserves 190 2,858 3,048 (1) Estimated proven and probable coal reserves have been adjusted to account for estimated process dilutions and losses during mining and processing involved in producing a saleable coal product. Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows: • Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. • Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation. Our estimates of proven and probable coal reserves are established within these guidelines. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density. Peabody Energy Corporation 2020 Form 10-K 40 Table of Contents Our guidelines for geologic assurance surrounding estimated proven and probable U.S. and Australian coal reserves generally follow the respective industry-accepted practices of those countries. In the U.S., our estimated proven coal reserves lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas, while our estimated probable coal reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. In Australia, our estimated proven coal reserves generally lie within 250 meters of a point of observation, while our estimated probable coal reserves may lie more than 250 meters, but less than 500 meters, from a point of observation. For some of our Australian coal reserves, the distance between points of observation is determined by a geostatistical study. The preparation of our coal reserve estimates is completed in accordance with our prescribed internal control procedures, which include verification of input data into a coal reserve forecasting and economic evaluation software system, as well as multi-functional management review. Our reserve estimates are prepared by our staff of experienced geologists and engineers. Our corporate Technical Services group is responsible for tracking changes in reserve estimates, supervising our other geologists and coordinating periodic third-party reviews of our reserve estimates by qualified mining consultants. Our coal reserve estimates are predicated on information obtained from an extensive historical database of drill holes and information obtained from our ongoing drilling program. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of a drill pattern determines whether the related coal reserves will be classified as proven or probable. Our coal reserve estimates are then input into our computerized land management system, which overlays that geological data with data on ownership or control of the mineral and surface interests to determine the extent of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantity and quality (where available) of reserves, as well as production data, surface and coal ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our coal reserve estimates to reflect production of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors. Our estimate of the economic recoverability of our coal reserves is generally based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review coal production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates consider dilutions and losses during mining and processing for recoverability factors to estimate a saleable product. Factors impacting our assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities. The estimates are also impacted by decreases resulting from current year production and increases resulting from information obtained from additional drilling. Our estimation as of December 31, 2020 reflected a net reduction compared to the prior year of 1.0 billion tons of coal reserves. The decrease was driven by production, changes to our estimates of economic recoverability to reflect market conditions, mine plan changes and new drilling. We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability. Our December 31, 2020 reserve estimates for the Gateway North Mine and El Segundo Mine in the U.S. were audited by Weir International, Inc., independent mining and geological consulting firm, which included a review of the data, procedures and parameters employed by us in developing our reserve estimates. The audits found that the reserve estimates for the areas were (1) well documented, clearly and concisely reported and (2) prepared consistent with standard industry and geological practice, and in accordance with United States Geological Survey Circular 891 requirements and SEC Industry Guide 7 guidelines. We plan to complete additional audits of our reserve estimates on a cyclical basis for each of our major operating regions. With respect to the accuracy of our coal reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. Peabody Energy Corporation 2020 Form 10-K 41 Table of Contents For each mine or future mine, we employ a market-driven, risk adjusted capital allocation process to guide long-term mine planning of active operations and development projects for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning. The LOM plan projects, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically recoverable coal in the LOM plan. Pricing The pricing information used to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected steel demand, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress tested against independent third-party research not commissioned by us to confirm the conclusions reached through our analytical processes, and our price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review. Below is a description of some of the specific factors that we evaluate in developing our price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in our price forecasts and realized factors could cause actual pricing to differ from our forecasts. Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include reserve positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines). In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices. Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. 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, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others. Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply. 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, as well as country-specific policies restricting or promoting domestic supply. 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, is also an important price consideration. In addition to the factors noted above, the prices which may be obtained at each individual mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships. Peabody Energy Corporation 2020 Form 10-K 42 Table of Contents Costs The cost estimates we use to establish our reserves are generally estimated according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Our estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the cost at our various operations include: • Geological settings . The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control. • Scale of operations and the equipment sizes . For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than room-and-pillar operations for underground mines. • Commodity prices . For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof bolts represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models we use to establish our reserves. • Target product quality . By targeting a premium quality product, our mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands. • Transportation costs . Transportation costs vary by region. Most of our U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in our U.S. thermal cost estimates. Our seaborne operations typically sell coal at designated ports. The estimated costs for our seaborne operations include rail and barge transportation and related fees at ports. • Royalty costs . Our royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs. • Exchange rates . Costs related to our Australian production are predominantly denominated in Australian dollars, while the Australian coal that we export is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production. Based on our mine-by-mine and product-by-product evaluations of the estimated prices for our coal, and the costs and expenses of mining and selling our coal, we have concluded our reserves were economically recoverable as of December 31, 2020. On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures. We have numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in the Powder River Basin and other reserves in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2020, we leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 640 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,645 acres nationwide subject to those limitations. Peabody Energy Corporation 2020 Form 10-K 43 Table of Contents Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,783 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments in the U.S. Private U.S. coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically. Mining and exploration in Australia is generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions. Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves. Peabody Energy Corporation 2020 Form 10-K 44 Table of Contents The following charts provide a summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2020, 2019 and 2018, tonnage of coal reserves that are assigned to our active operating mines, our property interest in those reserves and other characteristics of the facilities. SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES (Tons in millions) Sulfur Content of Assigned Reserves as of December 31, 2020 (1) <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As Production Sulfur Sulfur Sulfur Received Year Ended December 31, Type of Dioxide per Dioxide per Dioxide per Btu per Segment/Mining Complex 2020 2019 2018 Coal Million Btu Million Btu Million Btu pound (2) Seaborne Thermal Mining: Wilpinjong 14.2 14.1 14.1 T 93 — — 10,000 Wambo (3) 5.5 5.6 5.2 T/C 118 — — 11,300 Total 19.7 19.7 19.3 211 — — Seaborne Metallurgical Mining: Coppabella 2.2 2.4 2.7 P 22 — — 12,600 Moorvale 1.2 1.7 2.1 C/P/T 6 — — 12,500 Metropolitan 1.0 1.5 1.7 C/P/T 16 — — 12,600 Shoal Creek 0.6 1.9 0.2 C 52 — — 12,700 Millennium (4) 0.1 0.6 1.9 C/P — — — — North Goonyella — — 1.4 C 69 — — 12,700 Middlemount (5) — — — C/P 20 — — 12,400 Total 5.1 8.1 10.0 185 — — Powder River Basin Mining: North Antelope Rochelle 66.1 85.3 98.3 T 1,546 — — 8,800 Caballo 11.6 12.6 11.3 T 435 6 — 8,400 Rawhide 9.5 10.1 9.5 T 192 44 — 8,300 Total 87.2 108.0 119.1 2,173 50 — Other U.S. Thermal Mining: Bear Run 5.2 6.8 6.9 T 4 25 201 10,900 El Segundo/Lee Ranch 4.6 5.5 5.5 T 1 19 4 9,100 Wild Boar 2.0 2.5 2.7 T — — 27 11,100 Gateway North 1.8 3.0 3.1 T — — 46 10,900 Francisco Underground 1.6 2.0 2.2 T — — 8 11,370 Twentymile 1.2 2.6 3.1 T 4 — — 11,200 Somerville Central (6) 0.4 1.2 2.0 T — — — 11,000 Kayenta (7) — 3.8 6.5 T — — — — Wildcat Hills Underground (8) — 1.4 1.3 T — — — — Cottage Grove (9) — 0.1 0.4 T — — — — Total 16.8 28.9 33.7 9 44 286 Total Assigned 128.8 164.7 182.1 2,578 94 286 T: Thermal C: Coking P: Pulverized Coal Injection Metallurgical Peabody Energy Corporation 2020 Form 10-K 45 Table of Contents ASSIGNED RESERVES (10) AS OF DECEMBER 31, 2020 (Tons in millions) Attributable Ownership 100% Project Basis Modifying Factors (11) Proven and Probable Reserves Proven and Probable Reserves Segment/Mining Complex Interest Owned Leased Surface Underground Owned Leased Surface Underground ROM Factor Yield Seaborne Thermal Mining: Wilpinjong 100% 93 — 93 93 — 93 — 93 93 — 104 % 86 % Wambo (3) (a) 118 — 118 33 85 151 — 151 66 85 100 % 74 % Total 211 — 211 126 85 Seaborne Metallurgical Mining: Coppabella 73.3% 22 — 22 22 — 30 — 30 30 — 92 % 78 % Moorvale 73.3% 6 — 6 6 — 8 — 8 8 — 107 % 79 % Metropolitan 100% 16 — 16 — 16 16 — 16 — 16 109 % 84 % Shoal Creek 100% 52 — 52 — 52 52 — 52 — 52 102 % 56 % North Goonyella 100% 69 — 69 — 69 69 — 69 — 69 105 % 82 % Middlemount (5) 50% 20 — 20 20 — 40 — 40 40 — 86 % 77 % Total 185 — 185 48 137 Powder River Basin Mining: North Antelope Rochelle 100% 1,546 — 1,546 1,546 — 1,546 — 1,546 1,546 — 92 % 100 % Caballo 100% 441 — 441 441 — 441 — 441 441 — 90 % 100 % Rawhide 100% 236 — 236 236 — 236 — 236 236 — 93 % 100 % Total 2,223 — 2,223 2,223 — Other U.S. Thermal Mining: Bear Run 100% 230 108 122 230 — 230 108 122 230 — 106 % 72 % El Segundo/Lee Ranch 100% 24 23 1 24 — 24 23 1 24 — 87 % 100 % Wild Boar 100% 27 11 16 27 — 27 11 16 27 — 107 % 76 % Gateway North 100% 46 44 2 — 46 46 44 2 — 46 64 % 62 % Francisco Underground 100% 8 2 6 — 8 8 2 6 — 8 64 % 64 % Twentymile 100% 4 2 2 — 4 4 2 2 — 4 117 % 67 % Total 339 190 149 281 58 Total Assigned 2,958 190 2,768 2,678 280 Peabody Energy Corporation 2020 Form 10-K 46 Table of Contents ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (10) AS OF DECEMBER 31, 2020 (Tons in millions) Attributable Ownership 100% Project Basis Proven and Proven and Total Tons Probable Total Tons Probable Coal Seam Location Assigned Unassigned Reserves Proven Probable Assigned Unassigned Reserves Proven Probable Seaborne Thermal Mining (New South Wales) 211 — 211 146 65 244 — 244 176 68 Seaborne Metallurgical Mining: Alabama 52 — 52 51 1 52 — 52 51 1 New South Wales 16 — 16 2 14 16 — 16 2 14 Queensland 117 90 207 168 39 147 120 267 212 55 Total 185 90 275 221 54 Powder River Basin Mining (Wyoming) 2,223 — 2,223 2,108 115 2,223 — 2,223 2,108 115 Other U.S. Thermal Mining: Illinois 46 — 46 15 31 46 — 46 15 31 Indiana 265 — 265 195 70 265 — 265 195 70 New Mexico 24 — 24 24 — 24 — 24 24 — Colorado 4 — 4 4 — 4 — 4 4 — Total 339 — 339 238 101 Total Proven and Probable 2,958 90 3,048 2,713 335 Peabody Energy Corporation 2020 Form 10-K 47 Table of Contents ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD AS OF DECEMBER 31, 2020 (Tons in millions) Attributable Ownership 100% Project Basis Reserve Control Mining Method Reserve Control Mining Method Coal Seam Location Owned Leased Surface Underground Owned Leased Surface Underground Seaborne Thermal Mining (New South Wales) — 211 126 85 — 244 159 85 Seaborne Metallurgical Mining: Alabama — 52 — 52 — 52 — 52 New South Wales — 16 — 16 — 16 — 16 Queensland — 207 54 153 — 267 85 182 Total — 275 54 221 Powder River Basin Mining (Wyoming) — 2,223 2,223 — — 2,223 2,223 — Other U.S. Thermal Mining: Illinois 44 2 — 46 44 2 — 46 Indiana 121 144 257 8 121 144 257 8 New Mexico 23 1 24 — 23 1 24 — Colorado 2 2 — 4 2 2 — 4 Total 190 149 281 58 Total Proven and Probable 190 2,858 2,684 364 Peabody Energy Corporation 2020 Form 10-K 48 Table of Contents ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT AS OF DECEMBER 31, 2020 (Tons in millions) Attributable Ownership 100% Project Basis Sulfur Content (1) Sulfur Content (1) <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Received Type of per per per per per per Btu Coal Seam Location Coal Million Btu Million Btu Million Btu Million Btu Million Btu Million Btu per Pound (2) Seaborne Thermal Mining (New South Wales) T/C 211 — — 244 — — 10,700 Seaborne Metallurgical Mining: Alabama C 52 — — 52 — — 12,700 New South Wales C/P/T 16 — — 16 — — 12,600 Queensland C/P/T 207 — — 267 — — 12,400 Total 275 — — Powder River Basin Mining (Wyoming) T 2,173 50 — 2,173 50 — 8,700 Other U.S. Thermal Mining: Illinois T — — 46 — — 46 10,800 Indiana T 4 25 236 4 25 236 11,000 New Mexico T 1 19 4 1 19 4 9,150 Colorado T 4 — — 4 — — 11,200 Total 9 44 286 Total Proven and Probable 2,668 94 286 T: Thermal C: Coking P: Pulverized Coal Injection Metallurgical Peabody Energy Corporation 2020 Form 10-K 49 Table of Contents (1) Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal. (2) As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves. (3) Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas. (4) The Company’s Millennium Mine ceased production in March 2020, with sales continuing throughout May 2020. (5) Represents our 50% interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. Because that entity is accounted for as an unconsolidated equity affiliate, 2020, 2019 and 2018 tons produced by Middlemount have been excluded from the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table. Middlemount produced 3.2 million tons, 2.9 million tons, and 4.2 million tons of coal in 2020, 2019 and 2018, respectively (on a 100% basis). (6) The Company’s Somerville Central Mine ceased production in December 2020, with sales continuing into January 2021. (7) The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona. (8) The Company’s Wildcat Hills Underground Mine ceased production in December 2019, with sales continuing throughout April 2020. (9) The Company’s Cottage Grove Mine ceased production in May 2019, with sales continuing throughout July 2019. (10) Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2020. Unassigned reserves represent coal at currently non-producing locations that would require significant new mine development, mining equipment or plant facilities before operations could begin on the property. (11) The modifying factors reflect the assumptions which are utilized to convert coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually to saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity, which takes into account any losses and dilutions during mining and processing. We generally keep track of coal reserves through in place coal, ROM coal and product coal. In place coal for U.S. underground reserves excludes planned barrier pillars, but includes regular pillars from projected underground extractions. In place coal for Australian underground reserves is exclusive of all planned pillars. The difference is due to historic practice and software used by each country. The ROM factor represents the estimated ROM coal in relation to the coal in place with considerations of coal losses, dilutions and remaining pillars during mining processes. The yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. a. In December 2019, after receiving the requisite regulatory and permitting approvals, the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Wambo Open-Cut reserve is estimated for our 50% interest in United Wambo Joint Venture. Item 3. Legal Proceedings. See Note 24. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference. Item 4. Mine Safety Disclosures. Our “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across our business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees. We continually monitor our safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Annual Report on Form 10-K. Peabody Energy Corporation 2020 Form 10-K 50 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Our Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 16, 2021 there were 140 holders of our Common Stock, as determined by counting our record holders and the number of participants reflected in a security position listing provided to us by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of our Common Stock on behalf of their customers, we do not know the actual number of unique shareholders represented by these record holders. Dividend Policy We declared and paid quarterly dividends every quarter in 2019, and a supplemental dividend was declared and paid during the first quarter of 2019. We suspended dividends in 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, we entered into transaction support agreements with our surety bond providers which prohibit the payment of dividends through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to pay cash dividends. Share Relinquishments We routinely allow employees to relinquish Common Stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in Common Stock under our equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of our Common Stock on the dates of the respective relinquishments. Share Repurchase Programs On August 1, 2017, we announced that our Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of our common stock and/or preferred stock (Repurchase Program). On April 25, 2018, we announced that the Board authorized the expansion of the Repurchase Program to $1.0 billion. On October 30, 2018, we announced that the Board authorized an additional expansion of the Repurchase Program to $1.5 billion. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2020, we repurchased 41.5 million shares of our Common Stock for $1,340.3 million, which included commissions paid of $0.8 million, leaving $160.5 million available for share repurchase under the Repurchase Program. We suspended share repurchases in 2019, and similar to the payment of dividends as described above, the same agreements with our surety bond providers prohibit share repurchases through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to repurchase shares. Prior to the suspension, repurchases were made at the Company’s discretion. The specific timing, price and size of purchases depended upon the share price, general market and economic conditions and other considerations, including compliance with various debt agreements in effect at the time the repurchases were made. Purchases of Equity Securities The following table summarizes all share purchases for the three months ended December 31, 2020: Period Total Number of Shares Purchased (1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program Maximum Dollar Value of Shares that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions) October 1 through October 31, 2020 276 $ 2.20 — $ 160.5 November 1 through November 30, 2020 — — — 160.5 December 1 through December 31, 2020 443 1.99 — 160.5 Total 719 2.07 — (1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program. Peabody Energy Corporation 2020 Form 10-K 51 Table of Contents Mandatory Conversion of Preferred Shares Each share of our Series A Convertible Preferred Stock (Convertible Preferred Stock) that was previously outstanding was subject to mandatory automatic conversion into a number of shares of Common Stock if the volume weighted average price of the Common Stock exceeded $32.50 for at least 45 trading days in a 60 consecutive trading day period, including each of the last 20 days in such 60 consecutive trading day period. On January 31, 2018, the requirements for such a mandatory conversion were met and the then outstanding 13.2 million shares of Convertible Preferred Stock were automatically converted into 24.8 million shares of Common Stock. As a result of this mandatory conversion, we recorded a non-cash preferred dividend charge of $102.5 million during the year ended December 31, 2018. After the mandatory conversion, no shares of Convertible Preferred Stock are issued or outstanding and all rights of the prior holders of Convertible Preferred Stock have terminated. Stock Performance Graph The following performance graph compares the cumulative total return on our common stock from April 4, 2017, the date our common stock began trading following the effective date of our plan of reorganization, through December 31, 2020, with the cumulative total return of the following indices: (i) the S&P MidCap 400 Stock Index and (ii) Custom Composite Index (a peer group comprised of Arch Resources, Inc., Hallador Energy Co., and Warrior Met Coal, Inc.). The Custom Composite Index reflects publicly listed U.S. companies within the coal industry of similar size or product type. The graph assumes that the value of the investment was $100 at April 4, 2017 for BTU and the Custom Composite Index (Warrior Met Coal, Inc. began trading on the New York Stock Exchange on April 13, 2017) and at March 31, 2017, for the S&P Midcap 400 Index. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2020. These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved and are not intended to forecast or be indicative of possible future performance of the common stock. Peabody Energy Corporation 2020 Form 10-K 52 Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Overview In 2020, we produced and sold 128.8 million and 132.6 million tons of coal, respectively, from continuing operations. 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. The business of our seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of our thermal and metallurgical coal sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. We classify our seaborne mines within the Seaborne Thermal Mining or Seaborne Metallurgical Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Seaborne Thermal Mining segment is of a metallurgical grade. Similarly, a small portion of the coal mined by the Seaborne Metallurgical Mining segment is of a thermal grade. Additionally, we may market some of our metallurgical coal products as a thermal coal product from time to time depending on market conditions. Our Seaborne Thermal Mining operations consist of mines in New South Wales, Australia. The mines in that segment utilize both surface and underground extraction processes to mine low-sulfur, high Btu thermal coal. Our Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and PCI coal. The principal business of our thermal mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. Our Powder River Basin Mining operations consist of our mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). Our Other U.S. Thermal Mining operations historically reflect the aggregation of our Illinois, Indiana, New Mexico, Colorado and Arizona mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, our Powder River Basin Mining operations mine sub-bituminous coal deposits and our Other U.S. Thermal Mining operations mine both bituminous and sub-bituminous coal deposits. Our Corporate and Other segment includes selling and administrative expenses, including our technical and shared services functions; results from equity affiliates; corporate hedging activities; trading and brokerage activities; results from certain mining and export/transportation joint ventures; minimum charges on certain transportation-related contracts; the closure of inactive mining sites; and certain commercial matters. Resource Management. As of December 31, 2020, we controlled approximately 3.0 billion tons of proven and probable coal reserves and approximately 450,000 acres of surface property through ownership and lease agreements. We have an ongoing asset optimization program whereby our property management group regularly reviews these reserves and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves and surface lands. These surface lands include acres where we have completed post-mining reclamation. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface lands under third-party contracts. Middlemount Mine. We own a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and LV PCI coal for sale into seaborne coal markets through Abbot Point Coal Terminal, with some capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011. During the years ended December 31, 2020, 2019 and 2018, the mine sold 3.2 million, 2.9 million and 4.2 million tons of coal, respectively (on a 100% basis). Peabody Energy Corporation 2020 Form 10-K 53 Table of Contents Coronavirus (COVID-19) Pandemic On March 11, 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. The pandemic has resulted in governments around the world implementing stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of the COVID-19 pandemic. Coal mining in the U.S. and Australia has been designated as an essential business to support coal-fueled electric power generation and critical steelmaking needs. As part of Peabody’s commitment to the ongoing health and safety of our employees, vendors and communities, we are following advice from government authorities and taking precautions to manage the spread of COVID-19. Peabody operations have implemented rigorous protocols, control and prevention measures, including mandatory temperature and health checks; paid leave for recommended self-isolation periods; enhanced cleaning and sterilization practices; expanded use of personal protective equipment; social distancing; and working remotely when circumstances warrant. While our operations have been designated as essential, each operation will only continue to operate when it is safe and economic to do so. The global impact on economic activity has severely curtailed demand for numerous commodities. Within the global coal industry, supply and demand disruptions have been widespread. The global economy is showing improvement in industrial production, even as the timing of a recovery varies across countries and sectors. However, in the seaborne metallurgical and thermal markets, demand remains below pre-pandemic levels. In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. During the year ended December 31, 2020, coal-fueled generation declined approximately 20% compared to the prior year period and now represents 19% of the overall generation mix. Additionally, we have faced limited disruption to supply chain and distribution channels and adverse effects to our workforce. Coal industry fundamentals, as well as known impacts specific to Peabody, are further addressed in the “Results of Operations” section contained within this Item 7. While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may negatively affect both demand and prices for our products. Given the uncertainties with respect to future COVID-19 developments, including the duration, severity and scope, as well as the necessary government actions to limit the spread, we are unable to estimate the full impact of the pandemic on our business, financial condition, results of operations or cash flows at this time. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (the CARES Act), a $2 trillion economic relief bill, was enacted in the U.S.. The CARES Act contained numerous income tax provisions, including a provision that provides for the acceleration of refunds of previously generated alternative minimum tax credits. Pursuant to the CARES Act, we received approximately $24 million of accelerated refunds from the Internal Revenue Service and adjusted our current and deferred tax asset balances accordingly. The CARES Act also contained a provision for deferred payment of 2020 employer payroll taxes after the date of enactment to future years. We deferred a portion of our remaining 2020 employer payroll taxes to subsequent years. North Goonyella Mine Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018 and mining operations have been suspended since then. In 2020, we commenced a review of strategic alternatives for North Goonyella which is currently ongoing. During the years ended December 31, 2019 and 2018, we recorded provisions for equipment losses of $83.2 million and $66.4 million, respectively, related to the fire, representing the best estimate of losses to date. No additional provisions for equipment losses were recorded during the year ended December 31, 2020. We have also incurred containment and idling costs subsequent to the mine’s suspension which amounted to $32.3 million, $111.5 million and $58.0 million during the years ended December 31, 2020, 2019 and 2018, respectively. In March 2019, we entered into an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amount of the recovery. Peabody Energy Corporation 2020 Form 10-K 54 Table of Contents Results of Operations Non-GAAP Financial Measures The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to business combinations and joint ventures as management does not view these items as part of our normal operations. Also included in the following discussion of our results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of our mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7. In our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations. We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7 for definitions and reconciliations to the most comparable measures under U.S. GAAP. Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 Summary Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 2020 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2020 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the year ended December 31, 2020 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly 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. Competition from alternative fuels such as natural gas and other fuel sources may also impact our realized pricing. High Low Average December 31, 2020 Premium HCC (1) $ 163.40 $ 97.60 $ 124.11 $ 101.60 Premium PCI coal (1) $ 102.80 $ 65.75 $ 78.42 $ 91.50 Newcastle index thermal coal (1) $ 85.31 $ 47.99 $ 60.24 $ 83.72 API 5 thermal coal (1) $ 59.63 $ 35.16 $ 44.74 $ 55.00 PRB 8,800 Btu/Lb coal (2) $ 12.10 $ 11.55 $ 11.83 $ 11.85 Illinois Basin 11,500 Btu/Lb coal (2) $ 33.80 $ 27.75 $ 30.27 $ 29.75 (1) Prices expressed per tonne. (2) Prices expressed per ton. Peabody Energy Corporation 2020 Form 10-K 55 Table of Contents Within the global coal industry, supply and demand disruptions have been widespread as the COVID-19 pandemic has forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. The global coal industry data for the year ended December 31, 2020 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration, and potential for continued weak demand for our products. With respect to seaborne metallurgical coal, global steel production decreased approximately 1% during the year ended December 31, 2020 compared to the prior year, with significant declines in most regions due to the impacts of COVID-19, offset by another year of strong growth in China. Excluding China, steel production was down approximately 10%, while Chinese steel production increased approximately 5% from 2019. While global steel production remained lower year-over-year, there has been consistent improvement in steel production since July 2020 as COVID-19 related lockdown restrictions eased in key countries. Improved steel demand has enabled steelmakers, including Peabody customers, to restart capacity and increase output, resulting in improvements in seaborne metallurgical coal demand. For example, India seaborne metallurgical coal imports set a new all-time monthly volume record each month from October to December. Elsewhere, the recovery continues steadily with most countries operating at or just below pre-COVID-19 levels. A key risk to demand for Australian metallurgical coal in 2021 is China’s import policies, which have largely prohibited the buying of Australian products since October 2020 and an end date to the limitations is currently unclear. Within the seaborne thermal coal market, demand has been below pre-pandemic levels in many key countries, and headwinds such as COVID-19, China import restrictions and competition from alternative fuel sources persist. China thermal imports were up 6 million tonnes through the year ended December 31, 2020. India has seen domestic power demand recover, but thermal imports are down by approximately 25 million tonnes through the year ended December 31, 2020 compared to the prior year. In the United States, overall electricity demand has been negatively impacted year-over-year due to COVID-19 induced economic shutdowns and mild weather during the year ended December 31, 2020. The reduction in thermal coal demand during that period has exceeded the reduction in overall electricity demand as continued coal plant retirements, and growth in natural gas and renewable generation negatively impacted coal’s share of electricity generation. Lower total electricity demand driven by COVID-19 related curtailments has resulted in coal’s share of generation declining to approximately 19% for the year ended December 31, 2020, while natural gas and renewables increased. Through the year ended December 31, 2020 utility consumption of PRB coal fell approximately 20% compared to the prior year period. Our revenues for the year ended December 31, 2020 decreased compared to the same period in 2019 ($1,742.3 million) primarily due to lower sales volumes which were affected by the COVID-19 pandemic and lower realized prices. Results from continuing operations, net of income taxes for the year ended December 31, 2020 decreased compared to the same period in the prior year ($1,671.5 million). The decrease was driven by the unfavorable revenue variance described above, higher asset impairment charges recorded in the current period ($1,217.2 million) and a prior year insurance recovery related to the events at our North Goonyella Mine ($125.0 million). These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($1,011.7 million) and lower depreciation, depletion and amortization ($255.0 million). Adjusted EBITDA for the year ended December 31, 2020 reflected a year-over-year decrease of $624.2 million. As of December 31, 2020, our available liquidity was approximately $729 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of factors affecting our available liquidity. Peabody Energy Corporation 2020 Form 10-K 56 Table of Contents Tons Sold The following table presents tons sold by operating segment: (Decrease) Increase Year Ended December 31, to Volumes 2020 2019 Tons % (Tons in millions) Seaborne Thermal Mining 19.0 19.5 (0.5) (2.6) % Seaborne Metallurgical Mining 5.6 8.1 (2.5) (30.9) % Powder River Basin Mining 87.2 108.1 (20.9) (19.3) % Other U.S. Thermal Mining 18.3 27.9 (9.6) (34.4) % Total tons sold from mining segments 130.1 163.6 (33.5) (20.5) % Corporate and Other 2.5 1.9 0.6 31.6 % Total tons sold 132.6 165.5 (32.9) (19.9) % Supplemental Financial Data The following table presents supplemental financial data by operating segment: Year Ended December 31, (Decrease) Increase 2020 2019 $ % Revenues per Ton - Mining Operations (1) Seaborne Thermal $ 37.46 $ 49.69 $ (12.23) (24.6) % Seaborne Metallurgical 86.33 127.62 (41.29) (32.4) % Powder River Basin 11.37 11.37 — — % Other U.S. Thermal 38.73 46.85 (8.12) (17.3) % Costs per Ton - Mining Operations (1) (2) Seaborne Thermal $ 28.87 $ 32.84 $ (3.97) (12.1) % Seaborne Metallurgical (3) 109.44 110.30 (0.86) (0.8) % Powder River Basin 9.14 9.32 (0.18) (1.9) % Other U.S. Thermal 29.51 33.91 (4.40) (13.0) % Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) Seaborne Thermal $ 8.59 $ 16.85 $ (8.26) (49.0) % Seaborne Metallurgical (3) (23.11) 17.32 (40.43) (233.4) % Powder River Basin 2.23 2.05 0.18 8.8 % Other U.S. Thermal 9.22 12.94 (3.72) (28.7) % (1) This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. (2) Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. (3) Costs incurred at the North Goonyella Mine from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred at the North Goonyella Mine during the year ended December 31, 2019 remain within the Seaborne Metallurgical Mining segment and resulted in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton of $9.59. Peabody Energy Corporation 2020 Form 10-K 57 Table of Contents Revenues The following table presents revenues by reporting segment: Decrease Year Ended December 31, to Revenues 2020 2019 $ % (Dollars in millions) Seaborne Thermal Mining $ 711.8 $ 971.7 $ (259.9) (26.7) % Seaborne Metallurgical Mining 486.5 1,033.1 (546.6) (52.9) % Powder River Basin Mining 991.1 1,228.7 (237.6) (19.3) % Other U.S. Thermal Mining 707.3 1,309.4 (602.1) (46.0) % Corporate and Other (15.6) 80.5 (96.1) (119.4) % Revenues $ 2,881.1 $ 4,623.4 $ (1,742.3) (37.7) % Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2020 compared to the prior year was driven by unfavorable realized coal pricing ($220.3 million) and unfavorable volume and mix variances ($39.6 million). Seaborne Metallurgical Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to unfavorable volume and mix variances ($340.8 million) resulting from demand-based volume decreases across our mines and unfavorable realized coal pricing ($205.8 million). Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year period due to demand-based volume decreases ($244.3 million) and the prior year benefit of a contract settlement with a PRB customer ($19.7 million). These unfavorable variances were partially offset by favorable realized coal pricing ($26.4 million). Other U.S. Thermal Mining. The decrease in segment revenues for the year ended December 31, 2020 compared to the same period in the prior year was primarily due to volume decreases ($453.6 million) which were driven by the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Wildcat Hills Underground Mine during the second quarter of 2020, the prior year benefit of revenues associated with the final commercial negotiations for the Kayenta Mine ($127.8 million) and unfavorable realized coal pricing ($20.7 million). Corporate and Other. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to lower results on economic hedge activities. Adjusted EBITDA The following table presents Adjusted EBITDA for each of our reporting segments: (Decrease) Increase to Year Ended December 31, Adjusted EBITDA 2020 2019 $ % (Dollars in millions) Seaborne Thermal Mining $ 163.2 $ 329.4 $ (166.2) (50.5) % Seaborne Metallurgical Mining (130.2) 140.2 (270.4) (192.9) % Powder River Basin Mining 194.8 221.2 (26.4) (11.9) % Other U.S. Thermal Mining 168.4 361.4 (193.0) (53.4) % Corporate and Other (137.4) (169.2) 31.8 18.8 % Adjusted EBITDA (1) $ 258.8 $ 883.0 $ (624.2) (70.7) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year as a result of lower realized net coal pricing ($202.4 million), unfavorable volume variances ($12.6 million) and the unfavorable impacts of a temporary shutdown at our Wambo Underground Mine ($12.2 million). The decrease was partially offset by favorable mine sequencing impacts and lower costs for materials, services and repairs at our thermal surface mines ($35.6 million) and lower pricing for fuel ($14.0 million). Peabody Energy Corporation 2020 Form 10-K 58 Table of Contents Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to lower realized net coal pricing ($188.0 million), unfavorable volume variances ($138.7 million) and higher costs at our Shoal Creek Mine, including those related to a conveyor upgrade ($51.1 million). These negative variances were partially offset by the inclusion of North Goonyella Mine containment and holding costs within our Corporate and Other segment in the current year ($77.6 million) and lower pricing for fuel ($10.9 million). Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to the impact of lower volumes ($43.6 million), the prior year net benefit of a contract settlement with a PRB customer ($24.0 million) and unfavorable mine sequencing impacts ($22.2 million). These negative variances were partially offset by lower costs for materials, services, repairs and labor ($31.1 million), lower pricing for fuel and explosives ($23.5 million) and higher realized net coal pricing ($6.5 million). Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the impact of lower volumes ($135.4 million) as described above, the prior year net benefit associated with the final commercial negotiations for the Kayenta Mine ($83.3 million), lower realized net coal pricing ($37.8 million) and unfavorable mine sequencing impacts ($12.9 million). These unfavorable variances were partially offset by lower costs for materials, services, repairs and labor ($42.4 million) and lower pricing for fuel and explosives ($16.8 million). Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: (Decrease) Increase Year Ended December 31, to Income 2020 2019 $ % (Dollars in millions) Middlemount (1) $ (29.2) $ (9.8) $ (19.4) (198.0) % Resource management activities (2) 15.3 8.2 7.1 86.6 % Selling and administrative expenses (99.5) (145.0) 45.5 31.4 % Other items, net (3)(4) (24.0) (22.6) (1.4) (6.2) % Corporate and Other Adjusted EBITDA $ (137.4) $ (169.2) $ 31.8 18.8 % (1) Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $29.9 million and $25.1 million during the years ended December 31, 2020 and 2019, respectively. (2) Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. (3) Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and expenses related to our other commercial activities. (4) North Goonyella costs incurred from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred prior to January 1, 2020 remain within the Seaborne Metallurgical Mining segment. The increase in Corporate and Other Adjusted EBITDA during the year ended December 31, 2020 compared to the same period in the prior year was due to lower selling and administrative expenses driven by lower personnel costs; the favorable impact of changes made to one of our postretirement health care benefit plans during the third quarter of 2020 ($14.9 million); resource management gains recorded in the current period ($14.8 million); and favorable corporate hedging results ($10.7 million). These favorable results were partially offset by current year containment and holding costs for our North Goonyella Mine ($32.3 million) and an unfavorable variance in Middlemount’s results due to the continuing impacts of lower sales pricing and a significant change to the mine plan following a highwall failure in mid-2019. Peabody Energy Corporation 2020 Form 10-K 59 Table of Contents Loss From Continuing Operations, Net of Income Taxes The following table presents loss from continuing operations, net of income taxes: (Decrease) Increase to Income Year Ended December 31, 2020 2019 $ % (Dollars in millions) Adjusted EBITDA (1) $ 258.8 $ 883.0 $ (624.2) (70.7) % Depreciation, depletion and amortization (346.0) (601.0) 255.0 42.4 % Asset retirement obligation expenses (45.7) (58.4) 12.7 21.7 % Restructuring charges (37.9) (24.3) (13.6) (56.0) % Transaction costs related to joint ventures (23.1) (21.6) (1.5) (6.9) % Gain on formation of United Wambo Joint Venture — 48.1 (48.1) (100.0) % Asset impairment (1,487.4) (270.2) (1,217.2) (450.5) % Provision for North Goonyella equipment loss — (83.2) 83.2 100.0 % North Goonyella insurance recovery - equipment — 91.1 (91.1) (100.0) % Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates (30.9) 18.8 (49.7) (264.4) % Interest expense (139.8) (144.2) 4.4 3.1 % Interest income 9.4 27.0 (17.6) (65.2) % Net mark-to-market adjustment on actuarially determined liabilities 5.1 (67.4) 72.5 107.6 % Unrealized (losses) gains on economic hedges (29.6) 42.2 (71.8) (170.1) % Unrealized gains on non-coal trading derivative contracts 7.1 1.2 5.9 491.7 % Take-or-pay contract-based intangible recognition 8.2 16.6 (8.4) (50.6) % Income tax provision (8.0) (46.0) 38.0 82.6 % Loss from continuing operations, net of income taxes $ (1,859.8) $ (188.3) $ (1,671.5) (887.7) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment: Increase (Decrease) Year Ended December 31, to Income 2020 2019 $ % (Dollars in millions) Seaborne Thermal Mining $ (88.0) $ (90.7) $ 2.7 3.0 % Seaborne Metallurgical Mining (85.4) (125.3) 39.9 31.8 % Powder River Basin Mining (85.3) (148.5) 63.2 42.6 % Other U.S. Thermal Mining (72.1) (228.2) 156.1 68.4 % Corporate and Other (15.2) (8.3) (6.9) (83.1) % Total $ (346.0) $ (601.0) $ 255.0 42.4 % Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments: Year Ended December 31, 2020 2019 Seaborne Thermal Mining $ 1.90 $ 1.84 Seaborne Metallurgical Mining 2.30 3.09 Powder River Basin Mining 0.50 0.80 Other U.S. Thermal Mining 1.04 1.33 Peabody Energy Corporation 2020 Form 10-K 60 Table of Contents Depreciation, depletion and amortization expense decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Millennium and Wildcat Hills Underground Mines during the second quarter of 2020 ($122.7 million), the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 ($52.6 million), decreased depletion driven by lower sales volumes ($22.5 million) and lower amortization of contract based intangibles ($21.8 million). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the volume and mix variances which impacted our revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020. Asset Retirement Obligation Expenses. Asset retirement obligation expenses decreased during the year ended December 31, 2020 compared to the same period in the prior year as the result of favorable revisions to the estimates for our closed mines. Restructuring Charges. Restructuring charges increased during the year ended December 31, 2020 compared to the same period in the prior year as the result of workforce reductions made across the organization through the use of involuntary and voluntary reductions, as discussed in Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements. Transaction Costs Related to Joint Ventures. The charges recorded during the current and prior year periods related to the proposed PRB Colorado joint venture with Arch Resources, Inc. as further described in Note 20. “Other Events” to the accompanying consolidated financial statements. Gain on Formation of United Wambo Joint Venture. During the year ended December 31, 2019, we recognized a $48.1 million gain upon the formation of the United Wambo Joint Venture. Refer to Note 20. “Other Events” to the accompanying consolidated financial statements for further information regarding the calculation of the gain, which information is incorporated herein by reference. Asset Impairment. We recognized $1,487.4 million in aggregate asset impairment charges during the year ended December 31, 2020, primarily related to the fair value of our North Antelope Rochelle Mine in our Powder River Basin Mining segment. During the year ended December 31, 2019, we recognized $270.2 million in aggregate asset impairment charges primarily related to the El Segundo/Lee Ranch and Wildcat Hills Underground Mines in our Other U.S. Thermal Mining segment. Refer to Note 3. “Asset Impairment” to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference. Provision for North Goonyella Equipment Loss. A provision for expected equipment losses related to the events at our North Goonyella Mine was recorded during the prior year as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. North Goonyella Insurance Recovery - Equipment. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the years ended December 31, 2019 and 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019. Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2020, we established a valuation allowance on Middlemount’s net deferred tax position of approximately $33 million. During the year ended December 31, 2019, we released a tax reserve of approximately $17 million. Refer to Note 6. “Equity Method Investments” to the accompanying consolidated financial statements for further information regarding these changes, which information is incorporated herein by reference Interest Income. The decrease in interest income during the year ended December 31, 2020 compared to the prior year was driven by the conclusion of a contract during the fourth quarter of 2019 which contained an embedded financing element and by lower cash balances. Peabody Energy Corporation 2020 Form 10-K 61 Table of Contents Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2020 was driven by gains on pension and postretirement benefit plan assets ($73.7 million), the favorable impacts of a mortality update for all actuarially determined liabilities ($39.5 million) and changes related to claims for the postretirement benefit plans ($21.2 million). These increases were offset by decreases to the discount rates for all actuarially determined liabilities ($116.5 million). The expense recorded during the year ended December 31, 2019 was driven by decreases to the discount rates for all actuarially determined liabilities ($137.6 million) and the unfavorable impact of changes related to claims and an update to our census data for the postretirement benefits plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.5 million). Unrealized (Losses) Gains on Economic Hedges. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements. Take-or-Pay Contract-Based Intangible Recognition . During the years ended December 31, 2020 and 2019, we ratably recognized contract-based intangible liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 8. “Intangible Contract Assets and Liabilities” to the accompanying consolidated financial statements. Income Tax Provision . The decrease in the income tax provision during the year ended December 31, 2020 compared to the prior year period was primarily due to year-over-year decreases in taxable income, partially offset by an increase in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 10. “Income Taxes” to the accompanying consolidated financial statements for additional information. Net Loss Attributable to Common Stockholders The following table presents net loss attributable to common stockholders: Decrease to Year Ended December 31, to Income 2020 2019 $ % (Dollars in millions) Loss from continuing operations, net of income taxes $ (1,859.8) $ (188.3) $ (1,671.5) (887.7) % (Loss) income from discontinued operations, net of income taxes (14.0) 3.2 (17.2) (537.5) % Net loss (1,873.8) (185.1) (1,688.7) (912.3) % Less: Net (loss) income attributable to noncontrolling interests (3.5) 26.2 (29.7) (113.4) % Net loss attributable to common stockholders $ (1,870.3) $ (211.3) $ (1,659.0) (785.1) % (Loss) Income from Discontinued Operations, Net of Income Taxes . The decrease in results from discontinued operations, net of income taxes during the year ended December 31, 2020 compared to the prior year period was primarily driven by decreases to the discount rates for black lung liabilities. Net (Loss) Income Attributable to Noncontrolling Interests . The decrease in net results attributable to noncontrolling interests during the year ended December 31, 2020 compared to the prior year period was primarily due to lower results of our majority-owned mines in which there is an outside non-controlling interest. Diluted EPS The following table presents diluted EPS: Decrease to Year Ended December 31, EPS 2020 2019 $ % Diluted EPS attributable to common stockholders: Loss from continuing operations $ (18.99) $ (2.07) $ (16.92) (817.4) % (Loss) income from discontinued operations (0.15) 0.03 (0.18) (600.0) % Net loss attributable to common stockholders $ (19.14) $ (2.04) $ (17.10) (838.2) % Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 97.7 million and 103.7 million for the years ended December 31, 2020 and 2019, respectively. Peabody Energy Corporation 2020 Form 10-K 62 Table of Contents Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 Summary Spot pricing for Premium HCC, Premium PCI coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 2019 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2019 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the year ended December 31, 2019 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly 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. Competition from alternative fuels such as natural gas and other coal producers may also impact our realized pricing. High Low Average December 31, 2019 Premium HCC (1) $ 215.80 $ 127.30 $ 176.66 $ 136.10 Premium PCI coal (1) $ 129.85 $ 85.50 $ 110.50 $ 86.65 Newcastle index thermal coal (1) $ 99.78 $ 62.32 $ 77.74 $ 66.55 API 5 thermal coal (1) $ 62.87 $ 48.00 $ 54.41 $ 51.30 PRB 8,800 Btu/Lb coal (2) $ 12.60 $ 12.05 $ 12.22 $ 12.10 Illinois Basin 11,500 Btu/Lb coal (2) $ 47.50 $ 33.50 $ 38.83 $ 33.65 (1) Prices expressed per tonne. (2) Prices expressed per ton. With respect to seaborne metallurgical coal, global steel production increased approximately 3% through the year ended December 31, 2019 as compared to the prior year period. India imports increased approximately 5% through the year ended December 31, 2019, as compared to the prior year, amid domestic steel production growth of approximately 3% year-over-year. Steel production in China increased approximately 7% through the year ended December 31, 2019 as compared to the prior year, resulting in an approximate 15% increase in coking coal imports during the same period. Seaborne thermal coal demand and pricing was subdued due to restrictions in China and low gas prices coupled with elevated stockpiles in Europe, despite robust demand from India and other Asian regions. Chinese thermal coal imports increased by approximately 8 million tonnes through the year ended December 31, 2019 as compared to the prior year. Despite constraints by heightened mine safety inspections, China’s domestic production registered a 4.2% increase through the year ended December 31, 2019, as compared to the prior year period, supported by new mine approvals. India’s domestic production declined approximately 1% through the year ended December 31, 2019, which was not sufficient to meet growing demand from its industrial and power sectors. As a result, India’s thermal coal imports increased by approximately 6% or 10 million tonnes year-over-year through December 31, 2019. Demand from countries comprising the Association of Southeast Asian Nations (ASEAN) increased 23 million tonnes through the year ended December 31, 2019 as compared to the prior year, primarily led by Vietnam. In the United States, overall electricity demand was down year-over-year through the year ended December 31, 2019. Continued coal plant retirements, growth in natural gas and renewable generation and weak natural gas prices negatively impacted coal demand. For the year ended December 31, 2019, utility consumption of PRB coal fell approximately 16% as compared to the prior year due to ongoing pressure from retirements, wind generation and regional natural gas prices that traded at a discount to quoted Henry Hub natural gas spot prices. Our revenues for the year ended December 31, 2019 decreased as compared to the same period in 2018 ($958.4 million) primarily due to lower sales volumes and realized prices. Our Seaborne Metallurgical Mining segment was adversely impacted by the events at our North Goonyella Mine described above, as well as other production factors, partially offset by the incremental volume provided by our Shoal Creek Mine. Our Powder River Basin Mining segment was adversely impacted by lower demand and delays in rail shipments caused by severe flooding during the first half of 2019. Peabody Energy Corporation 2020 Form 10-K 63 Table of Contents Results from continuing operations, net of income taxes for the year ended December 31, 2019 decreased as compared to the same period in the prior year ($834.0 million). The decrease was driven by the unfavorable revenue variances described above, as well as asset impairment charges recorded in the current period ($270.2 million), the impact of a net mark-to-market loss on actuarially determined liabilities as compared to a gain in the prior year ($192.9 million) and approximately $20 million of expense in the current year related to the Monto litigation. These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($534.8 million) and an insurance recovery related to the events at our North Goonyella Mine ($125.0 million). The decrease in net results attributable to common stockholders during the year ended December 31, 2019 as compared to the same period in 2018 was partially offset by dividends ($102.5 million) recorded in the prior year period related to the convertible preferred stock issued in connection with our reorganization. Adjusted EBITDA for the year ended December 31, 2019 reflected a year-over-year decrease of $504.9 million. Tons Sold The following table presents tons sold by operating segment: Increase (Decrease) to Tons Sold Year Ended December 31, 2019 2018 Tons % (Tons in millions) Seaborne Thermal Mining 19.5 19.1 0.4 2.1 % Seaborne Metallurgical Mining 8.1 11.0 (2.9) (26.4) % Powder River Basin Mining 108.1 120.3 (12.2) (10.1) % Other U.S. Thermal Mining 27.9 33.6 (5.7) (17.0) % Total tons sold from mining segments 163.6 184.0 (20.4) (11.1) % Corporate and Other 1.9 2.7 (0.8) (29.6) % Total tons sold 165.5 186.7 (21.2) (11.4) % Peabody Energy Corporation 2020 Form 10-K 64 Table of Contents Supplemental Financial Data The following table presents supplemental financial data by operating segment: Year Ended December 31, (Decrease) Increase 2019 2018 $ % Revenues per Ton - Mining Operations (1) Seaborne Thermal $ 49.69 $ 57.58 $ (7.89) (13.7) % Seaborne Metallurgical 127.62 141.06 (13.44) (9.5) % Powder River Basin 11.37 11.84 (0.47) (4.0) % Other U.S. Thermal 46.85 41.46 5.39 13.0 % Costs per Ton - Mining Operations (1) (2) Seaborne Thermal $ 32.84 $ 33.90 $ (1.06) (3.1) % Seaborne Metallurgical (3) 110.30 100.97 9.33 9.2 % Powder River Basin 9.32 9.47 (0.15) (1.6) % Other U.S. Thermal 33.91 32.81 1.10 3.4 % Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) Seaborne Thermal $ 16.85 $ 23.68 $ (6.83) (28.8) % Seaborne Metallurgical (3) 17.32 40.09 (22.77) (56.8) % Powder River Basin 2.05 2.37 (0.32) (13.5) % Other U.S. Thermal 12.94 8.65 4.29 49.6 % (1) This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. (2) Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. (3) Includes the events at the North Goonyella Mine resulting in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton for Seaborne Metallurgical of $9.59 and $5.27 for the years ended December 31, 2019 and 2018, respectively. Revenues The following table presents revenues by reporting segment: Year Ended December 31, Decrease to Revenues 2019 2018 $ % (Dollars in millions) Seaborne Thermal Mining $ 971.7 $ 1,099.2 $ (127.5) (11.6) % Seaborne Metallurgical Mining 1,033.1 1,553.0 (519.9) (33.5) % Powder River Basin Mining 1,228.7 1,424.8 (196.1) (13.8) % Other U.S. Thermal Mining 1,309.4 1,393.0 (83.6) (6.0) % Corporate and Other 80.5 111.8 (31.3) (28.0) % Revenues $ 4,623.4 $ 5,581.8 $ (958.4) (17.2) % Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2019 compared to the prior year was primarily driven by unfavorable realized coal pricing ($131.9 million), partially offset by favorable volume and mix variances ($4.4 million). Seaborne Metallurgical Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to unfavorable volumes (2.9 million tons, $441.1 million). The unfavorable volume variance resulting from the transition to highwall mining at our Millennium Mine in September 2018, an extended longwall move at our Metropolitan Mine and various mine sequencing impacts (3.2 million tons, $424.4 million) and no volume from our North Goonyella Mine during 2019 (1.7 million tons, $337.6 million) was partially offset by incremental volume provided by our Shoal Creek Mine, acquired in December 2018 (2.0 million tons, $320.9 million). Segment revenues were further impacted by lower realized pricing ($78.8 million). Peabody Energy Corporation 2020 Form 10-K 65 Table of Contents Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year due to lower volume primarily attributable to lower demand and railroad closures and delays that resulted from severe flooding across the upper Great Plains during the first half of 2019 ($157.9 million) and unfavorable realized pricing ($57.9 million). These unfavorable variances were partially offset by a favorable contract settlement with a PRB customer ($19.7 million). Other U.S. Thermal Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to unfavorable volume and mix variances ($200.2 million) and unfavorable realized pricing ($11.2 million). These unfavorable variances were partially offset by revenues associated with the final commercial negotiations for the Kayenta Mine ($127.8 million). Corporate and Other. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to lower results on economic hedges. Adjusted EBITDA The following table presents Adjusted EBITDA for each of our reporting segments: Year Ended December 31, (Decrease) Increase to Adjusted EBITDA 2019 2018 $ % (Dollars in millions) Seaborne Thermal Mining $ 329.4 $ 452.0 $ (122.6) (27.1) % Seaborne Metallurgical Mining 140.2 441.4 (301.2) (68.2) % Powder River Basin Mining 221.2 284.5 (63.3) (22.2) % Other U.S. Thermal Mining 361.4 290.6 70.8 24.4 % Corporate and Other (169.2) (80.6) (88.6) (109.9) % Adjusted EBITDA (1) $ 883.0 $ 1,387.9 $ (504.9) (36.4) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year as a result of lower realized net coal pricing ($121.7 million) and unfavorable mine sequencing impacts and higher equipment maintenance costs among our thermal surface mines ($48.1 million), offset by improved longwall performance at our Wambo Underground Mine ($30.2 million) and favorable foreign currency impacts ($24.1 million). Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year due to unfavorable volume variances described above ($231.9 million). The impact of the negative volumes at our Australian mines ($356.8 million) was partially offset by the incremental volume provided by our Shoal Creek Mine ($124.9 million). The decrease in Segment Adjusted EBITDA was further impacted by lower realized net coal pricing ($71.6 million), mine sequencing impacts among our metallurgical surface operations ($62.6 million) and the net containment and holding costs at our North Goonyella Mine ($19.6 million). These negative variances were partially offset by favorable foreign currency impacts ($50.5 million). Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year due to the impact of lower volume ($78.7 million) described above, lower realized net coal pricing ($10.7 million) and unfavorable mine sequencing impacts ($10.0 million), partially offset by the net impact of the favorable contract settlement with a PRB customer ($24.0 million) and lower lease expenses due to early lease buyouts ($8.6 million). Other U.S. Thermal Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to the net impact associated with the final commercial negotiations for the Kayenta Mine ($83.3 million) and higher realized net coal pricing ($13.0 million), partially offset by the unfavorable impact of lower volume ($25.7 million). Peabody Energy Corporation 2020 Form 10-K 66 Table of Contents Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: Year Ended December 31, (Decrease) Increase to Income 2019 2018 $ % (Dollars in millions) Middlemount (1) $ (9.8) $ 51.1 $ (60.9) (119.2) % Resource management activities (2) 8.2 44.7 (36.5) (81.7) % Selling and administrative expenses (145.0) (158.1) 13.1 8.3 % Other items, net (3) (22.6) (18.3) (4.3) (23.5) % Corporate and Other Adjusted EBITDA $ (169.2) (80.6) $ (88.6) (109.9) % (1) Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $25.1 million and $46.8 million during the years ended December 31, 2019 and 2018, respectively. (2) Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. (3) Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations and expenses related to our other commercial activities. The decrease in Corporate and Other Adjusted EBITDA during the year ended December 31, 2019 compared to the same period in the prior year was primarily driven by an unfavorable variance in Middlemount’s results due to the temporary suspension of operations and a significant change to the mine plan following a highwall failure mid-2019 and resource management gains recorded in the prior year period related to the sale of surplus land assets in Queensland’s Bowen Basin ($20.6 million) and the sale of surplus coal resources associated with the Millennium Mine ($20.5 million). These unfavorable results were partially offset by lower selling and administrative expenses primarily related to outside services and lower personnel costs. Peabody Energy Corporation 2020 Form 10-K 67 Table of Contents (Loss) Income From Continuing Operations, Net of Income Taxes The following table presents (loss) income from continuing operations, net of income taxes: Year Ended December 31, (Decrease) Increase to Income 2019 2018 $ % (Dollars in millions) Adjusted EBITDA (1) $ 883.0 $ 1,387.9 $ (504.9) (36.4) % Depreciation, depletion and amortization (601.0) (679.0) 78.0 11.5 % Asset retirement obligation expenses (58.4) (53.0) (5.4) (10.2) % Restructuring charges (24.3) (1.2) (23.1) (1,925.0) % Transaction costs related to business combinations and joint ventures (21.6) (7.4) (14.2) (191.9) % Gain on formation of United Wambo Joint Venture 48.1 — 48.1 n.m. Asset impairment (270.2) — (270.2) n.m. Provision for North Goonyella equipment loss (83.2) (66.4) (16.8) (25.3) % North Goonyella insurance recovery - equipment 91.1 — 91.1 n.m. Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 18.8 18.3 0.5 2.7 % Interest expense (144.2) (151.3) 7.1 4.7 % Interest income 27.0 33.6 (6.6) (19.6) % Net mark-to-market adjustment on actuarially determined liabilities (67.4) 125.5 (192.9) (153.7) % Reorganization items, net — 12.8 (12.8) (100.0) % Unrealized gains on economic hedges 42.2 18.3 23.9 130.6 % Unrealized gains (losses) on non-coal trading derivative contracts 1.2 (0.7) 1.9 271.4 % Take-or-pay contract-based intangible recognition 16.6 26.7 (10.1) (37.8) % Income tax provision (46.0) (18.4) (27.6) (150.0) % (Loss) income from continuing operations, net of income taxes $ (188.3) $ 645.7 $ (834.0) (129.2) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment: (Decrease) Increase Year Ended December 31, to Income 2019 2018 $ % (Dollars in millions) Seaborne Thermal Mining $ (90.7) $ (88.4) $ (2.3) (2.6) % Seaborne Metallurgical Mining (125.3) (129.8) 4.5 3.5 % Powder River Basin Mining (148.5) (183.4) 34.9 19.0 % Other U.S. Thermal Mining (228.2) (268.8) 40.6 15.1 % Corporate and Other (8.3) (8.6) 0.3 3.5 % Total $ (601.0) $ (679.0) $ 78.0 11.5 % Peabody Energy Corporation 2020 Form 10-K 68 Table of Contents Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments: Year Ended December 31, 2019 2018 Seaborne Thermal Mining $ 1.84 $ 1.79 Seaborne Metallurgical Mining 3.09 0.94 Powder River Basin Mining 0.80 0.81 Other U.S. Thermal Mining 1.33 1.51 Depreciation, depletion and amortization expense decreased during the year ended December 31, 2019 as compared to the same period in the prior year primarily due to lower amortization of the fair value of certain U.S. coal supply agreements ($65.9 million), decreased expense at our North Goonyella Mine after the fire due to lower sales volumes and asset impairments ($19.2 million) and decreased expense related to the closures of the Kayenta and Cottage Grove Mines during the third quarter of 2019 ($23.7 million). The acquisition of the Shoal Creek Mine in the fourth quarter of 2018 partly offset the decrease in depreciation, depletion and amortization ($41.0 million) and was the driver of the year-over-year increase in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment. Restructuring Charges. Restructuring charges increased during the year ended December 31, 2019 compared to the same period in the prior year as the result of workforce reductions made during 2019 resulting from actions taken at the North Goonyella Mine, U.S. mine closures and reductions in overhead and support functions. Transaction Costs Related to Business Combinations and Joint Ventures. The increase in transaction costs was primarily related to the proposed PRB Colorado joint venture with Arch Resources, Inc. as further described in Note 20. “Other Events” to the accompanying consolidated financial statements. Gain on Formation of United Wambo Joint Venture . During the year ended December 31, 2019, we recognized a $48.1 million gain upon the formation of the United Wambo Joint Venture. Refer to Note 20. “Other Events” to the accompanying consolidated financial statements for further information regarding the calculation of the gain, which information is incorporated herein by reference. Asset Impairment. We recognized $270.2 million in aggregate asset impairment charges during the year ended December 31, 2019. Refer to Note 3. “Asset Impairment” to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference. Provision for North Goonyella Equipment Loss. Provisions for equipment losses related to the events at our North Goonyella Mine were recorded during the years ended December 31, 2019 and 2018 as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. The provision recorded during 2019 was incremental to the provisions recorded during 2018 and represents the best estimate of potential loss associated with these events based on assessments made to date. North Goonyella Insurance Recovery - Equipment. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the years ended December 31, 2019 and 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019. Interest Income. The decrease in interest income during the year ended December 31, 2019 as compared to the prior year was driven by lower cash balances. Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The expense recorded during the year ended December 31, 2019 was driven by decreases to the discount rates for all actuarially determined liabilities ($137.6 million) and the unfavorable impact of changes related to claims and an update to our census data for the postretirement benefits plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.5 million). The gain recorded during the year ended December 31, 2018 was driven by increases to the discount rates ($46.2 million), the favorable impact of changes related to claims ($54.2 million), updates to the Medicare law ($20.0 million) and an update to our census data ($7.7 million) for the postretirement benefit plans. The impact on our pension plans was small as actuarial losses on pension assets were largely offset by an increase in discount rates. Peabody Energy Corporation 2020 Form 10-K 69 Table of Contents Reorganization Items, Net. The reorganization items recorded during the year ended December 31, 2018 were impacted by a favorable adjustment to our former bankruptcy claims accrual due to settlement of claims. Unrealized Gains on Economic Hedges. Unrealized gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements. Take-or-Pay Contract-Based Intangible Recognition. During the years ended December 31, 2019 and 2018, we ratably recognized contract-based intangible liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 8. “Intangible Contract Assets and Liabilities” to the accompanying consolidated financial statements. Income Tax Provision. The increase in the income tax provision during the year ended December 31, 2019 as compared to the prior year period was primarily related to the tax impact of the gain on formation of the United Wambo Joint Venture recognized during the fourth quarter of 2019, the year-over-year change in the benefit recorded in continuing operations under the exception provisions within ASC 740-20-45-7 and the prior year tax benefit related to the release of valuation allowance on refundable alternative minimum tax credits. Refer to Note 10. “Income Taxes” to the accompanying consolidated financial statements for additional information. Net (Loss) Income Attributable to Common Stockholders The following table presents net (loss) income attributable to common stockholders: (Decrease) Increase to Year Ended December 31, to Income 2019 2018 $ % (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (188.3) $ 645.7 $ (834.0) (129.2) % Income from discontinued operations, net of income taxes 3.2 18.1 (14.9) (82.3) % Net (loss) income (185.1) 663.8 (848.9) (127.9) % Less: Series A Convertible Preferred Stock dividends — 102.5 (102.5) (100.0) % Less: Net income attributable to noncontrolling interests 26.2 16.9 9.3 55.0 % Net (loss) income attributable to common stockholders $ (211.3) $ 544.4 $ (755.7) (138.8) % Income from Discontinued Operations, Net of Income Taxes . The decrease in income from discontinued operations, net of income taxes during the year ended December 31, 2019 as compared to the prior year period was primarily driven by smaller actuarial gains associated with black lung liabilities. Series A Convertible Preferred Stock Dividends . The convertible preferred stock dividends for the year ended December 31, 2018 were comprised of the deemed dividends granted for all remaining shares of convertible preferred stock shares that were converted as of January 31, 2018. Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the year ended December 31, 2019 was primarily driven by the gain on formation of the United Wambo Joint Venture recognized during the fourth quarter of 2019. Diluted EPS The following table presents diluted EPS: Decrease to Year Ended December 31, EPS 2019 2018 $ % Diluted EPS attributable to common stockholders: (Loss) income from continuing operations $ (2.07) $ 4.28 $ (6.35) (148.4) % Income from discontinued operations 0.03 0.15 (0.12) (80.0) % Net (loss) income attributable to common stockholders $ (2.04) $ 4.43 $ (6.47) (146.0) % Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 103.7 million and 121.0 million for the years ended December 31, 2019 and 2018, respectively Peabody Energy Corporation 2020 Form 10-K 70 Table of Contents Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance, as displayed in the reconciliations below. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to business combinations and joint ventures as management does not view these items as part of our normal operations. Year Ended December 31, 2020 2019 2018 (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (1,859.8) $ (188.3) $ 645.7 Depreciation, depletion and amortization 346.0 601.0 679.0 Asset retirement obligation expenses 45.7 58.4 53.0 Restructuring charges 37.9 24.3 1.2 Transaction costs related to business combinations and joint ventures 23.1 21.6 7.4 Gain on formation of United Wambo Joint Venture — (48.1) — Asset impairment 1,487.4 270.2 — Provision for North Goonyella equipment loss — 83.2 66.4 North Goonyella insurance recovery - equipment — (91.1) — Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 30.9 (18.8) (18.3) Interest expense 139.8 144.2 151.3 Interest income (9.4) (27.0) (33.6) Net mark-to-market adjustment on actuarially determined liabilities (5.1) 67.4 (125.5) Reorganization items, net — — (12.8) Unrealized losses (gains) on economic hedges 29.6 (42.2) (18.3) Unrealized (gains) losses on non-coal trading derivative contracts (7.1) (1.2) 0.7 Take-or-pay contract-based intangible recognition (8.2) (16.6) (26.7) Income tax provision 8.0 46.0 18.4 Adjusted EBITDA $ 258.8 $ 883.0 $ 1,387.9 Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows: Year Ended December 31, 2020 2019 2018 (Dollars in millions) Operating costs and expenses $ 2,524.9 $ 3,536.6 $ 4,071.4 Unrealized gains (losses) on non-coal trading derivative contracts 7.1 1.2 (0.7) Take-or-pay contract-based intangible recognition 8.2 16.6 26.7 North Goonyella insurance recovery - cost recovery and business interruption — (33.9) — Net periodic benefit (credit) costs, excluding service cost (1.8) 19.4 18.1 Total Reporting Segment Costs $ 2,538.4 $ 3,539.9 $ 4,115.5 Peabody Energy Corporation 2020 Form 10-K 71 Table of Contents The following table presents Reporting Segment Costs by reporting segment: Year Ended December 31, 2020 2019 2018 (Dollars in millions) Seaborne Thermal Mining $ 548.6 $ 642.3 $ 647.2 Seaborne Metallurgical Mining 616.7 892.9 1,111.6 Powder River Basin Mining 796.3 1,007.5 1,140.3 Western U.S. Mining 538.9 948.0 1,102.4 Corporate and Other 37.9 49.2 114.0 Total Reporting Segment Costs $ 2,538.4 $ 3,539.9 $ 4,115.5 The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment: Year Ended December 31, 2020 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 19.0 5.6 87.2 18.3 Revenues $ 711.8 $ 486.5 $ 991.1 $ 707.3 Reporting Segment Costs 548.6 616.7 796.3 538.9 Adjusted EBITDA 163.2 (130.2) 194.8 168.4 Revenues per Ton $ 37.46 $ 86.33 $ 11.37 $ 38.73 Costs per Ton 28.87 109.44 9.14 29.51 Adjusted EBITDA Margin per Ton 8.59 (23.11) 2.23 9.22 Year Ended December 31, 2019 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 19.5 8.1 108.1 27.9 Revenues $ 971.7 $ 1,033.1 $ 1,228.7 $ 1,309.4 Reporting Segment Costs 642.3 892.9 1,007.5 948.0 Adjusted EBITDA 329.4 140.2 221.2 361.4 Revenues per Ton $ 49.69 $ 127.62 $ 11.37 $ 46.85 Costs per Ton 32.84 110.30 9.32 33.91 Adjusted EBITDA Margin per Ton 16.85 17.32 2.05 12.94 Peabody Energy Corporation 2020 Form 10-K 72 Table of Contents Year Ended December 31, 2018 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 19.1 11.0 120.3 33.6 Revenues $ 1,099.2 $ 1,553.0 $ 1,424.8 $ 1,393.0 Reporting Segment Costs 647.2 1,111.6 1,140.3 1,102.4 Adjusted EBITDA 452.0 441.4 284.5 290.6 Revenues per Ton $ 57.58 $ 141.06 $ 11.84 $ 41.46 Costs per Ton 33.90 100.97 9.47 32.81 Adjusted EBITDA Margin per Ton 23.68 40.09 2.37 8.65 Free Cash Flow is defined as net cash (used in) provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP. Year Ended December 31, 2020 2019 (Dollars in millions) Net cash (used in) provided by operating activities $ (9.7) $ 677.4 Net cash used in investing activities (206.7) (261.3) Add back: Amount attributable to acquisition of Shoal Creek Mine — 2.4 Free Cash Flow $ (216.4) $ 418.5 Outlook As part of its normal planning and forecasting process, Peabody utilizes a broad approach to develop macroeconomic assumptions for key variables, including country-level gross domestic product, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections for key demand centers for coal, electricity generation and steel. Specific to the U.S., the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates. Our estimates involve risks and uncertainties and are subject to change based on various factors as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Annual Report on Form 10-K. Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook. Peabody is continuing to monitor the rapidly evolving COVID-19 pandemic and any impacts related to both our near-term and long-term outlook. Near-Term Outlook The COVID-19 pandemic continues to impact the global economy, including demand and pricing for global coal markets. Ultimately, demand for seaborne coal will be dependent on the timing and scale of a COVID-19 recovery. Seaborne thermal coal markets have recently shown signs of improvement with Newcastle forward prices averaging over $80 per tonne in 2021. Colder than expected weather across Asia and Europe has resulted in record high power generation in key markets, driving global liquefied natural gas prices significantly higher and supporting increased seaborne thermal coal demand. In addition, seaborne thermal supply has been impacted by severe wet weather in Indonesia as well as COVID-related production disruptions in China and labor issues in Colombia. Peabody’s seaborne thermal segment is well positioned to serve that demand. Peabody Energy Corporation 2020 Form 10-K 73 Table of Contents While seaborne metallurgical coal pricing has improved from 2020 lows, disrupted metallurgical trade flows have contributed to short term pricing volatility. In addition, limitations on Australian imports into China as well as the scope and scale of a steel recovery in traditional regions continue to weigh on markets. China has continued to not import Australian coals even as the spread between Australian and non-Australian premium hard coking coals reached an all-time high in January 2021, resulting in China paying a significant premium for non-Australian metallurgical coal. However, outside of China, demand has started to pick up in the traditional markets of Japan and Korea as well as India. Peabody remains focused on improving its seaborne metallurgical segment cost profile, particularly at the Shoal Creek and Metropolitan Mines, and will continue to be cautious and deliberate in its actions to resume production at currently idled operations. U.S. thermal coal markets continue to be heavily influenced by natural gas prices, growth in renewable generation and weather. In 2020, coal's share of the generation mix declined to 19% from 23% in the prior year, while natural gas' share rose to 40% as prompt natural gas prices averaged $2.13 per mmBtu. While current natural gas forward prices are above a key competitive mark of $2.50 per mmBtu, coal demand continues to be impacted by secular decline. Peabody remains committed to continuing to serve its customers from its low-cost operations. Long-Term Outlook Current projections indicate a slow seaborne market recovery as the global economy continues to be impacted by COVID-19. Future supply and demand will be impacted by economic conditions and public policy related to the COVID-19 pandemic in key supply and demand centers. Further, we believe coal demand and use will be adversely impacted by the policy decisions of various governments, regulatory bodies, financial institutions and others with respect to concerns over the environmental and social impacts of coal generation. Seaborne Fundamentals . Peabody projects global seaborne metallurgical demand to show consistent, albeit modest, growth over the next several years. During this time, India is expected to account for the vast majority of overall demand growth amid significant steel capacity additions and lack of domestic reserves. ASEAN countries are also projected to be a notable contributor to growth as demand in Japan and Korea remains largely stable. Australia will continue to account for more than 50% of seaborne supply. For seaborne thermal, Peabody expects ASEAN countries and India to be drivers for seaborne coal demand growth due to increased electrification and economic gains. This growth is anticipated to more than offset declines from developed economies, including the U.S. and Europe. Seaborne thermal coal will continue to be sourced primarily from seaborne exporters Indonesia and Australia, along with Russia, Colombia, South Africa and the U.S., among others. U.S. Fundamentals. U.S. thermal coal demand continues to be pressured by the ongoing secular decline and is expected to continue to decline longer-term. Future demand will be highly dependent on natural gas prices, growth in renewable generation and other competing fuels, general economic conditions, weather, and policy and regulations, among other factors. Liquidity and Capital Resources Overview Our primary source of cash is proceeds from the sale of our coal production to customers. We have also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under our credit facilities and, from time to time, the issuance of securities. Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, and selling and administrative expenses. We have also used cash for dividends, share repurchases and early debt retirements. Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including the restrictions set forth under our debt and surety agreements, our net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. Our ability to early retire debt, declare dividends, or repurchase shares in the future will depend on our future financial performance, which in turn depends on the successful implementation of our strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to our industry, many of which are beyond our control. We have presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.” Peabody Energy Corporation 2020 Form 10-K 74 Table of Contents Liquidity As of December 31, 2020, our cash balances totaled $709.2 million, including approximately $555 million held by U.S. subsidiaries and $136 million held by Australian subsidiaries, approximately $107 million of which was held by the subsidiary which conducts the operations of our Wilpinjong Mine. Our remaining balance was held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by our foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. We experienced negative cash flows from operations during the year ended December 31, 2020. Results from continuing operations, net of income taxes and Adjusted EBITDA for the year ended December 31, 2020 declined by $1,671.5 million and $624.2 million, respectively, compared to the year ended December 31, 2019. Our total liquidity declined from $1,275.8 million at December 31, 2019 to $728.7 million at December 31, 2020. Available liquidity as of December 31, 2020 and 2019 was comprised of the following: December 31, 2020 December 31, 2019 (Dollars in millions) Cash and cash equivalents $ 709.2 $ 732.2 Revolving credit facility availability 0.2 498.6 Accounts receivable securitization program availability 19.3 45.0 Total liquidity $ 728.7 $ 1,275.8 During the year ended December 31, 2020, the combined availability under our revolving credit facility and accounts receivable securitization program decreased as a result of $375.0 million of borrowings, $159.0 million of which was subsequently repaid, an additional $237.0 million of letters of credit issuances, a $46.1 million reduction in available receivable balances under the accounts receivable securitization program, and the maturity of a $25.0 million commitment under the revolving credit facility. As further described in Note 23. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees,” we are party to various guarantees and financial instruments to provide support for our reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. At December 31, 2020, such instruments included $1,633.6 million face amount of surety bonds and $437.6 million of outstanding letters of credit. As further described below, we have reached an agreement with the majority of our surety bond providers to limit future collateral requests related to surety bonding. Existing Debt Financing As described in Note 12. “Long-term Debt” of the accompanying consolidated financial statements, during 2017, we entered into an indenture related to the issuance of $500.0 million of 6.000% senior secured notes due March 2022 and $500.0 million of 6.375% senior secured notes due March 2025. We make semi-annual interest payments on the senior notes each March 31 and September 30 until maturity. Also during 2017, we entered into a credit agreement (the Credit Agreement) and related term loan under which we originally borrowed $950.0 million and have repaid $561.0 million through December 31, 2020. The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025. We entered into the revolving credit facility allowable under our Credit Agreement during 2017 for an aggregate commitment of $350.0 million for general corporate purposes. In September 2019, we entered into an amendment to the Credit Agreement which increased the aggregate commitment amount under the revolver to $565.0 million and, beginning in 2020, made applicable interest rates and fees dependent upon our periodically-determined first lien leverage ratio, as defined in the Credit Agreement. During 2020, we utilized the revolving credit facility to borrow $315.0 million, of which we subsequently repaid $99.0 million. At December 31, 2020, the revolving loan balance of $216.0 million bore interest at LIBOR plus 3.25%. The revolving credit facility was also utilized for letters of credit, amounting to $323.8 million at December 31, 2020, which incur combined fees of 3.375%, while unused capacity bears a commitment fee of 0.5%. Such letters of credit were primarily in support of our reclamation obligations. Our debt agreements impose various restrictions and limits on certain categories of payments that we may make, such as those for dividends, investments, and stock repurchases. We are also subject to customary affirmative and negative covenants. Peabody Energy Corporation 2020 Form 10-K 75 Table of Contents Refinancing and Related Transactions 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. Such agreements and related activities are described below. Organizational Realignment In July and August 2020, we effected certain changes to our corporate structure in contemplation of a debt-for-debt exchange, which included, among other steps, the formation of certain wholly-owned subsidiaries (the Co-Issuers) to indirectly own and conduct the operations of our Wilpinjong Mine in Australia and the designation of such entities as unrestricted subsidiaries under the Credit Agreement and our senior notes’ indenture (the Existing Indenture). In connection with these actions, we contributed $100.0 million to the Co-Issuers to provide the Wilpinjong Mine with operating liquidity and address its capital needs over the next twelve months. Surety Agreement In November 2020, we entered into a surety transaction support agreement (Surety Agreement) with the providers of 99% of our surety bond portfolio (Participating Sureties) to resolve approximately $800 million in additional collateral demands made by the Participating Sureties. In accordance with the Surety Agreement, we initially provided $75.0 million of collateral, in the form of letters of credit. Upon completion of the Refinancing Transactions, as defined below, other provisions of the Surety Agreement became effective. In particular, we granted second liens on $200.0 million of certain mining equipment and will post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the Participating Sureties. The collateral postings may also further increase to the extent we generate more than $100.0 million of free cash flow (as defined in the Surety Agreement) in any twelve-month period or have asset sales in excess of $10.0 million. Further, the Participating Sureties have agreed to a standstill through December 31, 2024, during which time, the Participating Sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves, or cancel any existing surety bond. We will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties. Refinancing Transactions On January 29, 2021 (the Settlement Date), we completed a series of transactions (collectively, the Refinancing Transactions) to, among other things, provide us with maturity extensions and covenant relief, while allowing us to maintain sufficient operating liquidity and financial flexibility. The Refinancing Transactions included a senior notes exchange and related consent solicitation, a revolving credit facility exchange, and various amendments to our existing debt agreements, as summarized below. Exchange Offer On January 29, 2021, we settled an exchange offer (Exchange Offer) pursuant to which $398.7 million aggregate principal amount of our 6.000% Senior Secured Notes due March 2022 (2022 Notes) were validly tendered, accepted by us and exchanged for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 10.000% Senior Secured Notes due 2024 issued by the Co-Issuers (New Co-Issuer Notes), (b) $195.1 million aggregate principal amount of new 8.500% Senior Secured Notes due 2024 issued by Peabody (New Peabody Notes), and (c) a cash payment of approximately $9.4 million. In connection with the settlement of the Exchange Offer, we also paid early tender premiums totaling $4.0 million in cash. Refer to Note 12. “Long-term Debt” for additional information associated with the New Co-Issuer Notes and the New Peabody Notes. Following the settlement of the Exchange Offer, approximately $60.3 million aggregate principal amount of the 2022 Notes remain outstanding and are governed by the Existing Indenture, as amended by the supplemental indenture described below. In connection with the Exchange Offer, we must offer to purchase up to $22.5 million New Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest, subsequent to the Settlement Date. We expect to complete this purchase during the first quarter of 2021. Peabody Energy Corporation 2020 Form 10-K 76 Table of Contents Consent Solicitation Concurrently with the Exchange Offer, we solicited consents from holders of the 2022 Notes to certain proposed amendments to the Existing Indenture to (i) eliminate substantially all of the restrictive covenants, certain events of default applicable to the 2022 Notes and certain other provisions contained in the Existing Indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other related provisions contained in the Existing Indenture. The Company received the requisite consents from holders of the 2022 Notes and entered into a supplemental indenture to the Existing Indenture, which became operative on January 29, 2021. Revolver Transactions In connection with the Refinancing Transactions, we restructured the revolving loans under the Credit Agreement by (i) making a pay down of revolving loans thereunder in the aggregate amount of $10.0 million, (ii) the Co-Issuers incurring $206.0 million of term loans under a credit agreement, dated as of the Settlement Date (New Co-Issuer Term Loans, New Co-Issuer Term Loan Agreement), (iii) Peabody entering into a letter of credit facility (the New Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions). The New Co-Issuer Term Loans mature on December 31, 2024 and bear interest at a rate of 10.00% per annum. On the Settlement Date, we entered into the New Company LC Agreement with the revolving lenders party to the Credit Agreement, pursuant to which we obtained a $324.0 million letter of credit facility under which our existing letters of credit under the Credit Agreement were deemed to be issued. The commitments under the New Company LC Agreement mature on December 31, 2024. Undrawn letters of credit under the New Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee. In connection with the Revolver Transactions, we amended the Credit Agreement to make certain changes in consideration of the New Company LC Agreement. After giving effect to the Revolver Transactions, there remain no revolving commitments or revolving loans under the Credit Agreement and the first lien net leverage ratio covenant was eliminated, effectively negating the compliance requirement at December 31, 2020. The New Company LC Agreement requires that our restricted subsidiaries maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024. As such, liquidity attributable to the Co-Issuers will be excluded from the calculation. Considering the Refinancing Transactions, we expect to incur approximately $200 million of interest expense, including approximately $50 million of non-cash interest expense, during the year ended December 31, 2021. Accounts Receivable Securitization Program As described in Note 23. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying consolidated financial statements, we entered into an amended accounts receivable securitization program during 2017 which currently expires in 2022. The program provides for up to $250.0 million in funding, limited to the availability of eligible receivables, accounted for as a secured borrowing. Funding capacity under the program may also be provided for letters of credit in support of other obligations. At December 31, 2020, we had no outstanding borrowings and $112.3 million of letters of credit provided under the program. The letters of credit are primarily in support of portions of our obligations for property and casualty insurance. Capital Requirements Additions to Property, Plant, Equipment and Mine Development. For 2021, we are targeting capital expenditures of approximately $225 million, which includes approximately $135 million for ongoing extension projects primarily related to our Seaborne Thermal Mining segment. We have no substantial future payment requirements under U.S. federal coal reserve leases. Peabody Energy Corporation 2020 Form 10-K 77 Table of Contents Historical Cash Flows and Free Cash Flow The following table summarizes our cash flows for the year ended December 31, 2020 and 2019, as reported in the accompanying consolidated financial statements: Year Ended December 31, 2020 2019 (Dollars in millions) Net cash (used in) provided by operating activities $ (9.7) $ 677.4 Net cash used in investing activities (206.7) (261.3) Net cash provided by (used in) financing activities 193.4 (701.3) Net change in cash, cash equivalents and restricted cash (23.0) (285.2) Cash, cash equivalents and restricted cash at beginning of period 732.2 1,017.4 Cash, cash equivalents and restricted cash at end of period $ 709.2 $ 732.2 Net cash (used in) provided by operating activities $ (9.7) $ 677.4 Net cash used in investing activities (206.7) (261.3) Add back: Amount attributable to acquisition of Shoal Creek Mine — 2.4 Free Cash Flow $ (216.4) $ 418.5 Operating Activities. The net decrease in net cash (used in) provided by operating activities for the year ended December 31, 2020 compared to the prior year was driven by a year-over-year decrease in cash from our mining operations, partially offset by a favorable change in net cash flows associated with our working capital ($108.0 million), and higher funding of our pension and retiree healthcare plans during 2019 ($16.7 million). Investing Activities. The decrease in net cash used in investing activities for the year ended December 31, 2020 compared to the prior year was driven by lower capital expenditures ($87.8 million), partially offset by higher proceeds from insurance recoveries attributable to North Goonyella equipment in the prior year period ($23.2 million) and higher cash receipts from Middlemount in the prior year period ($14.7 million). Financing Activities. The increase in net cash provided by (used in) financing activities for the year ended December 31, 2020 compared to the prior year was driven by borrowings under our revolving credit facility and accounts receivable securitization program ($315.0 million and $60.0 million, respectively), greater common stock repurchases and dividends in the prior year ($329.9 million and $258.1 million, respectively), partially offset by higher long-term debt repayments in the current year ($98.4 million). Peabody Energy Corporation 2020 Form 10-K 78 Table of Contents Contractual Obligations The following is a summary of our contractual obligations as of December 31, 2020: Payments Due By Year Total Less than 1 Year 2 - 3 Years 4 - 5 Years More than 5 Years (Dollars in millions) Long-term debt obligations (principal and interest) (1) $ 1,787.3 $ 74.9 $ 781.8 $ 930.6 $ — Finance lease obligations (principal and interest) 33.3 17.1 7.3 1.2 7.7 Operating lease obligations (2) 72.4 24.8 34.4 9.4 3.8 Unconditional purchase obligations (3) 37.0 29.3 7.7 — — Coal reserve lease and royalty obligations 55.7 5.5 10.8 8.9 30.5 Take-or-pay obligations (4) 1,206.5 94.5 177.7 180.2 754.1 Other long-term liabilities (5) 2,756.0 243.3 346.1 325.0 1,841.6 Total contractual cash obligations $ 5,948.2 $ 489.4 $ 1,365.8 $ 1,455.3 $ 2,637.7 (1) Represents the original contractual maturities of our long-term debt obligations. The related interest on long-term debt was calculated using rates in effect at December 31, 2020 for the remaining contractual term of the outstanding borrowings. Following the completion of the Refinancing Transactions, our total long-term debt obligations (principal and interest) increased to $1,953.6 million. (2) Excludes contingent rents. Refer to Note 13. “Leases” to the accompanying consolidated financial statements for additional discussion of contingent rental agreements. (3) We routinely enter into purchase agreements with approved vendors for most types of operating expenses in the ordinary course of business. Our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material and though they are considered enforceable and legally binding, the related terms generally allow us the option to cancel, reschedule or adjust our requirements based on our business needs prior to the delivery of goods or performance of services. Accordingly, the commitments in the table above relate to orders to suppliers for capital purchases. (4) Represents various short- and long-term take-or-pay arrangements in Australia and the U.S. associated with rail and port commitments for the delivery of coal, including amounts relating to export facilities. (5) Represents estimated cash outflows for long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end-of-mine closure costs and exploration obligations. Also includes $15 million related to the settlement of the United Mine Workers of America (UMWA) 1974 Pension Plan Litigation described in Note 4. “Discontinued Operations” to the accompanying consolidated financial statements. We do not expect any of the $9.1 million of net unrecognized tax benefits reported in our consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits. Off-Balance Sheet Arrangements In the normal course of business, we are a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying consolidated balance sheets. At December 31, 2020, such instruments included $1,633.6 million of surety bonds and $437.6 million of letters of credit. Such financial instruments provide support for our reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. We periodically evaluate the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. We do not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in our consolidated balance sheets. Peabody Energy Corporation 2020 Form 10-K 79 Table of Contents As of December 31, 2020, the Company was party to financial instruments with off-balance sheet risk in support of the following obligations: Reclamation Health and welfare (1) Contract performance (2) Leased property and equipment Other (3) Total (Dollars in millions) Surety bonds and bank guarantees $ 1,451.9 $ 43.9 $ 83.7 $ 38.3 $ 15.8 $ 1,633.6 Letters of credit outstanding under revolving credit facility 220.9 90.4 7.5 5.0 — 323.8 Letters of credit outstanding under accounts receivable securitization program 94.1 17.7 0.5 — — 112.3 Other letters of credit — 1.5 — — — 1.5 1,766.9 153.5 91.7 43.3 15.8 2,071.2 Less: Letters of credit in support of surety bonds (4) (315.0) (29.6) — (1.2) — (345.8) Less: Cash collateral in support of surety bonds (4) (15.0) — — — — (15.0) Obligations supported, net $ 1,436.9 $ 123.9 $ 91.7 $ 42.1 $ 15.8 $ 1,710.4 (1) Obligations include pension and healthcare plans, workers’ compensation, and property and casualty insurance (2) Obligations pertain to customer and vendor contracts (3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration (4) Serve as collateral for certain surety bonds at the request of surety bond providers We could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, surety bonds or other obligations are required to be collateralized by cash or letters of credit. As described in Note 23. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements, we are required to provide various forms of financial assurance in support of our mining reclamation obligations in the jurisdictions in which we operate. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. Following our emergence from the Chapter 11 Cases, we shifted away from extensive self-bonding in the U.S. in favor of increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on our liquidity due to increased collateral requirements and surety and related fees. At December 31, 2020, we had total asset retirement obligations of $728.2 million which were backed by a combination of surety bonds, bank guarantees and letters of credit. Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas our accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date. Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 23. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to our accompanying consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk. Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. We are also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. Peabody Energy Corporation 2020 Form 10-K 80 Table of Contents Impairment of Long-Lived Assets. We evaluate our long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. We generally do not view short-term declines in thermal and metallurgical coal prices as a triggering event for conducting impairment tests because of historic price volatility. However, we generally view a sustained trend of depressed coal pricing (for example, over periods exceeding one year) as an indicator of potential impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in our operating costs, may result in the need for future adjustments to the carrying value of our long-lived mining assets and mining-related investments. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For our active mining operations, we generally group such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to ongoing operating sites or for expected salvage. For our development and exploration properties and portfolio of surface land and coal reserve holdings, we consider several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of a sale to a third party. When indicators of impairment are present, we evaluate our long-lived assets for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for our individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from our long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of our long-lived mining assets are derived from those developed in connection with our planning and budgeting process. We believe our assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying our projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves, surface lands and undeveloped coal properties excluded from our long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy). Impairment charges of $1,487.4 million of long-lived assets were recorded for the year ended December 31, 2020. The assumptions used are based on our best knowledge at the time we prepare our analysis but can vary significantly due to the volatile and cyclical nature of coal prices and demand, regulatory issues, unforeseen mining conditions, commodity prices and cost of labor. Additionally, the decline of coal-fired electricity generation in the U.S., driven by the reduced utilization of plants and plant retirements, sustained low natural gas pricing and the increased use of renewable energy sources, was a significant consideration in our analysis. These factors may cause us to be unable to recover all or a portion of the carrying value of our long-lived assets. We conducted a review of all other long-lived assets for recoverability as of December 31, 2020 and determined that no further impairment charge was necessary as of that date. See Note 3. “Asset Impairment” to our accompanying consolidated financial statements for additional information regarding impairment charges. Income Taxes. We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities to be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In our evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. As of December 31, 2020, we had valuation allowances for income taxes totaling $2,287.3 million. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made. Peabody Energy Corporation 2020 Form 10-K 81 Table of Contents Our liability for unrecognized tax benefits contains uncertainties because management is required to make assumptions and to apply judgment to estimate the exposures associated with our various filing positions. We recognize the tax benefit from an uncertain tax position only if it is “more likely than not” that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position must be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. As of December 31, 2020, we had net unrecognized tax benefits of $9.1 million included in recorded liabilities in the consolidated balance sheet. We believe that our judgments and estimates are reasonable; however, to the extent we prevail in matters for which liabilities have been established, or are required to pay amounts in excess of our recorded liabilities, our effective tax rate in a given period could be materially affected. On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Act) was signed into law making significant changes to the Internal Revenue Code. Key provisions of the Act that impact the Company include: (i) repeal of the corporate alternative minimum tax system, (ii) reduction of the U.S. federal corporate tax rate from 35% to 21% and (iii) the inclusion of foreign income from the new global intangible low-taxed income provision of the Act. See Note 10. “Income Taxes” to the accompanying consolidated financial statements for additional information regarding valuation allowances, unrecognized tax benefits and the Act. Postretirement Benefit and Pension Liabilities. We have long-term liabilities for our employees’ postretirement benefit costs and defined benefit pension plans. Our pension obligations are funded in accordance with the provisions of applicable laws and our policies. Liabilities for postretirement benefit costs are funded at our discretion. Expense for the year ended December 31, 2020 for postretirement benefit costs and pension liabilities totaled $1.1 million, while employer contributions were $36.3 million. An actuarial gain of $9.1 million was recorded for the year ended December 31, 2020. Each of these liabilities is actuarially determined and we use various actuarial assumptions, including the discount rate, future cost trends, demographic assumptions and expected asset returns to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. We make assumptions related to future trends for medical care costs in the estimates of postretirement benefit costs. Our medical trend assumption is developed by annually examining the historical trend of cost per claim data. In addition, we make assumptions related to rates of return on plan assets. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could affect our obligation to satisfy these or additional obligations. For our postretirement benefit obligation, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for our health care plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts. For Year Ended December 31, 2020 One-Percentage- Point Increase One-Percentage- Point Decrease (Dollars in millions) Health care cost trend rate: Effect on total net periodic postretirement benefit cost $ 2.0 $ (1.8) Effect on total postretirement benefit obligation $ 43.7 $ (37.0) For Year Ended December 31, 2020 One-Half Percentage- Point Increase One-Half Percentage- Point Decrease (Dollars in millions) Discount rate: Effect on total net periodic postretirement benefit cost $ 1.6 $ (1.8) Effect on total postretirement benefit obligation $ (22.1) $ 25.2 Expected return on assets: Effect on total net periodic postretirement benefit cost $ (0.1) $ 0.1 Peabody Energy Corporation 2020 Form 10-K 82 Table of Contents For our pension obligation, assumed discount rates and expected returns on assets have a significant effect on the expense and funded status amounts reported for our defined benefit pension plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts. For Year Ended December 31, 2020 One-Half Percentage- Point Increase One-Half Percentage- Point Decrease (Dollars in millions) Discount rate: Effect on total net periodic pension cost $ 2.5 $ (2.8) Effect on defined benefit pension plans’ projected benefit obligation $ (39.0) $ 42.6 Expected return on assets: Effect on total net periodic pension cost $ (4.1) $ 4.1 As a result of discretionary contributions made in recent years, our defined benefit pension plans have become nearly fully funded. As a result of the funding level, the asset allocation mix reflected Peabody’s target asset mix of 100% fixed income investments and the pensions plans’ assets provide a significant hedge to the funded status against interest rate movements. If the discount rate moves, Peabody’s actual results would be different than those shown above as substantially all of the change in the discount rate should be offset by changes to the expected return on plan assets. See Note 15. “Postretirement Health Care and Life Insurance Benefits” and Note 16. “Pension and Savings Plans” to the accompanying consolidated financial statements for additional information regarding postretirement benefit and pension plans. Asset Retirement Obligations. Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws and regulations in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Amortization associated with our asset retirement obligation assets was $26.7 million for the year ended December 31, 2020. Asset retirement obligation expenses for the year ended December 31, 2020 was $45.7 million and payments totaled $43.4 million. See Note 14. “Asset Retirement Obligations” to the accompanying consolidated financial statements for additional information regarding our asset retirement obligations. Contingent liabilities. From time to time, we are subject to legal and environmental matters related to our continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, we are required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses. A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. We accrue for legal and environmental matters within “Operating costs and expenses” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We provide disclosure surrounding loss contingencies when we believe that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs. Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in our consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. We include the interest component of any litigation-related penalties within “Interest expense” in our consolidated statements of operations. See Note 24. “Commitments and Contingencies” to the accompanying consolidated financial statements for further discussion of our contingent liabilities. Peabody Energy Corporation 2020 Form 10-K 83 Table of Contents Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The potential for changes in the market value of our coal and freight-related trading, crude oil, diesel fuel and foreign currency contract portfolios, as applicable, is referred to as “market risk.” Market risk related to our coal trading and freight-related contract portfolio, which includes bilaterally-settled and over-the-counter (OTC) exchange-settled trading, in addition to, from time to time, the brokered trading of coal, is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate our non-trading diesel fuel or foreign currency hedging portfolios, as applicable, or coal trading activities we employ in support of coal production (as discussed below). We attempt to manage market price risks through diversification, controlling position sizes and executing hedging strategies. Due to a lack of quoted market prices and the long-term, illiquid nature of the positions, we have not quantified market price risk related to our non-trading, long-term coal supply agreement portfolio. Coal Trading Activities and Related Commodity Price Risk Coal Price Risk Monitored Using VaR. We engage in direct and brokered trading of physical coal and freight-related commodities in OTC markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor, manage and hedge market price risk due to current and anticipated trading activities to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of market price risk, as measured by VaR, that we may assume at any point in time from our trading and brokerage activities. We generally account for our coal trading activities using the fair value method, which requires us to reflect contracts with third parties that meet the definition of a derivative at market value in our consolidated financial statements, with the exception of contracts for which we have elected to apply the normal purchases and normal sales exception. Our trading portfolio included futures, forwards and options as of December 31, 2020. The use of VaR allows us to quantify in dollars, on a daily basis, a measure of price risk inherent in our trading portfolio. VaR represents the expected loss in portfolio value due to adverse market price movements over a defined time horizon (liquidation period) within a specified confidence level. Our VaR model is based on a variance/co-variance approach, which captures our potential loss exposure related to future, forward, swap and option positions. Our VaR model assumes a 15-day holding period at the time of VaR measurement and produces an output corresponding with a 95% one-tailed confidence interval, which means that there is a one in 20 statistical chance that our portfolio could lose more than the VaR estimates during the assumed liquidation period. Our volatility calculation incorporates an exponentially weighted moving average algorithm based on price movements during the previous 60 market days, which makes our volatility more representative of recent market conditions while still reflecting an awareness of historical price movements. VaR does not estimate the maximum potential loss expected in the 5% of the time that changes in the portfolio value during the assumed liquidation period is expected to exceed measured VaR. We use stress testing and scenario analysis to help provide visibility in such cases, as discussed further below. VaR analysis allows us to aggregate market price risk across products in the portfolio, compare market price risk on a consistent basis and identify the drivers of risk and changes thereto over time. We use historical data to estimate price volatility as an input to VaR. Given our reliance on historical data, we believe VaR is reasonably effective in characterizing market price risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Nonetheless, an inherent limitation of VaR is that past changes in market price risk factors may not produce accurate predictions of future market price risk. Due to that limitation, combined with the subjectivity in the choice of the liquidation period and reliance on historical data to calibrate our models, we perform stress and scenario analyses as needed to estimate the impacts of market price changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market price-related risks. During the year ended December 31, 2020, the actual low, high and average VaR was $0.3 million, $3.0 million and $1.1 million, respectively. Peabody Energy Corporation 2020 Form 10-K 84 Table of Contents Other Risk Exposures. We also use our coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from our mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (such as the forward sale of coal to be produced and/or purchased) may ultimately involve instruments sensitive to market price risk, the sourcing of coal in these arrangements does not involve market risk sensitive instruments and does not encompass the commodity price risks that we monitor through VaR analysis, as discussed above. Future Realization. As of December 31, 2020, the total estimated future realization of the value of our trading portfolio is expected to occur over 2021 and 2022. We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance. Credit and Nonperformance Risk The fair values of our derivative instruments utilized for corporate hedging and coal trading activities reflect adjustments for credit risk, as necessary. Our exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. Our policy is to independently evaluate each counterparty’s creditworthiness prior to entering into transactions and to regularly monitor exposures. We manage our counterparty risk from our hedging activities related to foreign currency and fuel exposures, as applicable, through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect our position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay or perform. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset asset and liability positions with such counterparties and, to the extent required, we will post or receive margin amounts associated with exchange-cleared and certain OTC positions. We also continually monitor counterparty and contract nonperformance risk, if present, on a case-by-case basis. Foreign Currency Risk We have historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements. As of December 31, 2020, we had currency options outstanding with an aggregate notional amount of $575.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the first nine months of 2021. Assuming we had no foreign currency hedging instruments in place, our exposure in operating costs and expenses due to a $0.10 change in the Australian dollar/U.S. dollar exchange rate is approximately $110 to $120 million for the next twelve months. Based upon the Australian dollar/U.S. dollar exchange rate at December 31, 2020, the currency option contracts outstanding at that date would limit our net exposure to a $0.10 unfavorable change in the exchange rate to approximately $60 million for the next twelve months. Other Non-Coal Trading Activities — Commodity Price Risk Long-Term Coal Contracts. We predominantly manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year) to the extent possible, rather than through the use of derivative instruments. Sales under such agreements comprised approximately 89%, 88% and 87% of our worldwide sales (by volume) for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, we had approximately 89 million tons of U.S. thermal coal priced and committed for 2021. This includes approximately 73 million tons of PRB coal and 16 million tons of other U.S. thermal coal. We have the flexibility to increase volumes should demand warrant. We are estimating 2021 thermal coal sales volumes from our Seaborne Thermal Mining segment of 17.2 million tons comprised of thermal export volume of 9.5 million tons and domestic volume of 7.7 million tons. We are estimating full year 2021 metallurgical coal sales from our Seaborne Metallurgical Mining segment of 5.7 million tons. Sales commitments in the metallurgical coal market are typically not long-term in nature, and we are therefore subject to fluctuations in market pricing. Peabody Energy Corporation 2020 Form 10-K 85 Table of Contents Diesel Fuel Hedges. Previously, we managed price risk of the diesel fuel used in our mining activities through the use of derivatives, primarily swaps. As of December 31, 2020, we did not have any diesel fuel derivative instruments in place. We also manage the price risk of diesel fuel through the use of cost pass-through contacts with certain customers. We expect to consume 75 to 85 million gallons of diesel fuel during the next twelve months. A $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual diesel fuel costs by approximately $20 million based on our expected usage. Interest Rate Risk Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. From time to time, we manage our debt to achieve a certain ratio of fixed-rate debt and variable-rate debt as a percent of net debt through the use of various hedging instruments. As of December 31, 2020, we had approximately $1 billion of fixed-rate borrowings and $0.7 billion of variable-rate borrowings outstanding and had no interest rate swaps in place. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $7 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $14 million in the estimated fair value of these borrowings. Item 8. Financial Statements and Supplementary Data. See Part IV, Item 15. “Exhibits and Financial Statement Schedules” of this report for the information required by this Item 8, which information is incorporated by reference herein. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. Evaluation of Disclosure Controls and Procedures Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal accounting officer, on a timely basis. As of December 31, 2020, the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of December 31, 2020 were effective to provide reasonable assurance that the desired control objectives were achieved. Changes in Internal Control Over Financial Reporting We periodically review our internal control over financial reporting as part of our efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, we routinely review our system of internal control over financial reporting to identify potential changes to our processes and systems that may improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new systems; consolidating the activities of acquired business units; migrating certain processes to our shared services organizations and/or managed third parties; formalizing and refining policies, procedures and control documentation requirements; improving segregation of duties and adding monitoring controls. In addition, when we acquire new businesses, we incorporate our controls and procedures into the acquired business as part of our integration activities. There have been no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Peabody Energy Corporation 2020 Form 10-K 86 Table of Contents Management’s Report on Internal Control Over Financial Reporting Management is responsible for maintaining and establishing adequate internal control over financial reporting. An evaluation of the effectiveness of the design and operation of our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, as of the end of the period covered by this report was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. This evaluation is performed to determine if our internal controls over financial reporting provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2020. Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein. /s/ Glenn L. Kellow /s/ Mark A. Spurbeck Glenn L. Kellow President and Chief Executive Officer Mark A. Spurbeck Executive Vice President and Chief Financial Officer February 23, 2021 Peabody Energy Corporation 2020 Form 10-K 87 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and the Board of Directors of Peabody Energy Corporation Opinion on Internal Control over Financial Reporting We have audited Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Peabody Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive (loss) income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”) of the Company, and our report dated February 23, 2021 expressed an unqualified opinion thereon. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Ernst & Young, LLP St. Louis, Missouri February 23, 2021 Peabody Energy Corporation 2020 Form 10-K 88 Table of Contents Item 9B. Other Information. None. PART III Item 10. Directors, Executive Officers and Corporate Governance. The information required by Item 401 of Regulation S-K is included under the caption Proposal I - “Election of Directors” in our 2021 Proxy Statement and in Part I, Item 1. “Business” of this report under the caption “Information About Our Executive Officers.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Stock Ownership,” “Corporate Governance - Code of Business Conduct and Ethics” and “Additional Information Concerning the Board of Directors - Committee Overview - Audit Committee” in our 2021 Proxy Statement. Such information is incorporated herein by reference. Item 11. Executive Compensation. The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Additional Information Concerning the Board of Directors - Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in our 2021 Proxy Statement and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by Item 403 of Regulation S-K is included under the caption “Stock Ownership - Security Ownership of Directors and Management and Certain Beneficial Owners” in our 2021 Proxy Statement and is incorporated herein by reference. Equity Compensation Plan Information As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2020: (a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) Plan Category Equity compensation plans approved by security holders 1,026,326 (1) $ — (2) 7,297,347 Equity compensation plans not approved by security holders — — — Total 1,026,326 $ — 7,297,347 (1) Shares issuable pursuant to outstanding performance units and vested but not issued deferred stock units. Performance units are shown at target and could change based on actual metrics achieved. (2) The weighted-average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards. Refer to Note 18. “Share-Based Compensation” to the accompanying consolidated financial statements for additional information regarding the material features of our current equity compensation plans. Item 13. Certain Relationships and Related Transactions, and Director Independence. The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Review of Related Person Transactions” and “Additional Information Concerning the Board of Directors - Board Independence” in our 2021 Proxy Statement and is incorporated herein by reference. Peabody Energy Corporation 2020 Form 10-K 89 Table of Contents Item 14. Principal Accountant Fees and Services. The information required by Item 9(e) of Schedule 14A is included under the caption “Audit Fees” in our 2021 Proxy Statement and is incorporated herein by reference. PART IV Item 15. Exhibits and Financial Statement Schedules. (a) Documents Filed as Part of the Report (1) Financial Statements. The following consolidated financial statements of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are included herein on the pages indicated: Page Report of Independent Registered Public Accounting Firm F- 1 Consolidated Statements of Operations — For the Years Ended December 31, 2020, 2019 and 2018 F- 3 Consolidated Statements of Comprehensive (Loss) Income — For the Years Ended December 31, 2020, 2019 and 2018 F- 4 Consolidated Balance Sheets — December 31, 2020 and 2019 F- 5 Consolidated Statements of Cash Flows — For the Years Ended December 31, 2020, 2019 and 2018 F- 6 Consolidated Statements of Changes in Stockholders’ Equity — For the Years Ended December 31, 2020, 2019 and 2018 F- 8 Notes to Consolidated Financial Statements F- 9 (2) Financial Statement Schedules. The following financial statement schedule of Peabody Energy Corporation is at the page indicated: Page Valuation and Qualifying Accounts F- 71 All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are not applicable and, therefore, have been omitted. (3) Exhibits. The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K. Exhibit No. Description of Exhibit 2.1 Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code as revised March 15, 2017 (Incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017). 2.2 Order Confirming Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on March 17, 2017 (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017). 2.3 Asset Purchase Agreement, dated as of September 20, 2018, by and between Drummond Company, Inc. and Peabody Southeast Mining, LLC, and, for certain limited purposes, Peabody Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed September 24, 2018). 2.4 Implementation Agreement, dated as of June 18, 2019, between Peabody Energy Corporation and Arch Coal, Inc. (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K/A filed on June 19, 2019). Peabody Energy Corporation 2020 Form 10-K 90 Table of Contents 3.1 Fourth Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed April 3, 2017). 3.2 Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.3 of the Registrant’s Current Report on Form 8-K filed April 3, 2017). 4.1 Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant’s Form S-1 Registration Statement No. 333-55412, filed May 1, 2001). 4.2 Indenture, dated as of February 15, 2017, between Peabody Securities Finance Corporation and Wilmington Trust, National Association, as Trustee, governing 6.000% Senior Secured Notes due 2022 and 6.375% Senior Secured Notes due 2025 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed February 15, 2017). 4.3 First Supplemental Indenture, dated as of April 3, 2017, among the Registrant, Peabody Securities Finance Corporation, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017). 4.4 Second Supplemental Indenture, dated as of May 7, 2018, among the Registrant, NGS Acquisition Corp., LLC, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018). 4.5 Third Supplemental Indenture, dated as of August 9, 2018, between the Registrant and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018). 4.6 Fourth Supplemental Indenture, dated as of December 7, 2018, among the Registrant, Peabody Southeast Mining, LLC, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.6 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018). 4.7 Description of Securities (Incorporated by reference to Exhibit 4.7 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019). 4.8 Indenture dated as of January 29, 2021, by and among the Co-Issuers, Wilmington Trust, National Association, as trustee, and the Company (on a limited basis, to the extent of its obligations specifically set forth therein) (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on February 1, 2021). 4.9 Indenture dated as of January 29, 2021, by and among Peabody, the guarantors party thereto, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on February 1, 2021). 4.10 Seventh Supplemental Indenture, dated as of January 8, 2021, by and amon