PEABODY ENERGY CORP 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. As used in this report, the terms “Peabody” or “the Company” refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the Company’s 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). Cautionary Notice Regarding Forward-Looking Statements This report includes statements of Peabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act) 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 Peabody’s future financial performance. The Company uses 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 Peabody’s 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 Peabody believes 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 the Company’s control. Factors that could affect its results or an investment in its securities include, but are not limited to: • the Company’s profitability depends upon the prices it receives for its coal; • if a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenues and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts; • risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company; • the Company’s take-or-pay arrangements could unfavorably affect its profitability; • the Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets; • the Company could be negatively affected if it fails to maintain satisfactory labor relations; • the Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations; • the Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal; • the Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company; • the Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its 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 the Company’s products or its securities and its 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 the Company’s future financial results, liquidity and growth prospects; • the Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks; • if the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated; 30 • the Company’s future success depends upon its ability to continue acquiring and developing coal reserves that are economically recoverable; • the Company faces numerous uncertainties in estimating its economically recoverable coal reserves and inaccuracies in its 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 the Company’s operating standards; • the Company may undertake further repositioning plans that would require additional charges; • the Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by the coronavirus (COVID-19) pandemic and the related effects on public health; • the Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect; • the Company is subject to various general operating risks which may be fully or partially outside of its control; • the Company’s financial performance could be adversely affected by its funded indebtedness (Indebtedness); • despite the Company’s Indebtedness, it may still be able to incur more debt, which could further increase the risks associated with its Indebtedness; • the terms of the indentures governing the Company’s senior secured notes and the agreements and instruments governing its other Indebtedness and surety bonding obligations impose restrictions that may limit its operating and financial flexibility; • the number and quantity of viable financing and insurance alternatives available to the Company 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 its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its securities from consideration by those investors; • the price of Peabody’s securities may be volatile and could fall below the minimum allowed by New York Stock Exchange listing requirements; • Peabody’s 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 Peabody’s stock or repurchase of its stock is dependent on a number of factors, and future payments and repurchases cannot be assured; • the Company may not be able to fully utilize its deferred tax assets; • acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits; • Peabody’s 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 the Company’s reported financial results; and • other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q. When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in the Company’s other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect its results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of its Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 23, 2021. These forward-looking statements speak only as of the date on which such statements were made, and the Company undertakes no obligation to update these statements except as required by federal securities laws. 31 Table of Contents Overview Peabody is a leading coal producer. In 2020, the Company produced and sold 128.8 million and 132.6 million tons of coal, respectively, from continuing operations. At June 30, 2021, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to its mining operations, the Company markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts. The Company reports its 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 Note 18. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of its Corporate and Other segment. Financing and Surety Transactions During the fourth quarter of 2020 and the first quarter of 2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and certain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio. During the second quarter of 2021, and continuing into the third quarter of 2021, the Company completed a series of additional financing transactions intended to improve its capital structure. These transactions included at-the-market common stock issuances for cash proceeds, common stock issuances for the retirement of long-term debt and the retirement of long-term debt primarily through open market purchases. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of these financing and surety transactions. Other From time to time, the Company initiates restructuring activities in connection with its repositioning efforts to appropriately align its cost structure or optimize its coal production relative to prevailing market conditions. As further described in the “Results of Operations” section contained within this Item 2, the Company incurred restructuring charges of $2.1 million and $16.5 million during the three months ended June 30, 2021 and 2020, respectively, and $4.2 million and $23.0 million during the six months ended June 30, 2021 and 2020, respectively, related to workforce reductions made across the organization through both involuntary and voluntary reductions. The Shoal Creek Mine remains idled as the Company continues activities to increase productivity, lower costs and improve yields from the operation in the future. The preparation plant upgrade project remains on schedule with completion expected in the middle of the third quarter of 2021. The Shoal Creek labor contract expired in April 2021, and negotiations with the workforce are ongoing. The Metropolitan Mine full workforce returned to the mine in early May. Development work at the mine has been ongoing and longwall production restarted late in the second quarter of 2021, with a ramp up to planned production levels in the third quarter of 2021. The underground workforce enterprise agreement expired in January 2021 and after a period of ongoing negotiation, an application was made to terminate the underground labor agreement. That application is pending. Subsequent to June 30, 2021, the Company executed transactions to sell its closed Millennium and Wilkie Creek Mines to reduce its closed mine reclamation liabilities and associated costs. The Company is in process of assessing the financial impacts of the sales, but anticipates recording cumulative gains of $40 million to $50 million in the third quarter of 2021, with minimal cash consideration received. Results of Operations Non-GAAP Financial Measures The following discussion of the Company’s 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 its segments’ operating performance. 32 Table of Contents Also included in the following discussion of the Company’s 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 its 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. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes 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 2. In its discussion of liquidity and capital resources, the Company includes references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of its financial performance and its ability to generate excess cash flow from its business operations. The Company believes non-GAAP performance measures are used by investors to measure its operating performance and lenders to measure its 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 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP. Three and Six Months Ended June 30, 2021 Compared to the Three and Six Months Ended June 30, 2020 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 three months ended June 30, 2021 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2021 due to quality differentials and the majority of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. The Company’s 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 the Company realized during the three months ended June 30, 2021 since the Company generally sells 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 the Company’s realized pricing. High Low Average June 30, 2021 Premium HCC (1) $ 194.00 $ 106.50 $ 137.84 $ 194.00 Premium PCI coal (1) 144.75 104.25 117.11 144.75 Newcastle index thermal coal (1) 132.42 90.89 107.79 132.42 API 5 thermal coal (1) 73.11 54.64 61.02 73.11 PRB 8,800 Btu/Lb coal (2) 12.50 11.95 12.06 12.50 Illinois Basin 11,500 Btu/Lb coal (2) 40.00 32.00 33.89 40.00 (1) Prices expressed per tonne. (2) Prices expressed per ton. Within the global coal industry, supply and demand disruptions were widespread as the COVID-19 pandemic 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 six months ended June 30, 2021 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration. 33 Table of Contents Within the seaborne metallurgical coal market, record steel production and tight coal availability have driven Australian spot prices to the highest level in two years. China’s unofficial ban on Australian coal remains in place and continues to support delivered China prices above those of all other markets. This is incentivizing producers in Russia, the U.S. and Canada to supply China with additional volumes, providing opportunities for Australia to supply customers typically serviced by these countries. COVID-19 remains an ongoing risk to seaborne metallurgical coal demand and has recently impacted import volumes to India and Japan. Within the seaborne thermal coal market, tight supplies and elevated demand have driven Newcastle thermal coal pricing to levels not seen in over 10 years. China’s domestic thermal coal supply remains hampered by heightened safety inspections and mine suspensions. The relaxation of China’s import controls combined with tight domestic supply has pushed import demand higher. In addition, India’s thermal coal imports improved ahead of the monsoon season. However, supply response to elevated demand has been muted year-to-date, sending thermal coal prices higher. In the United States, overall electricity demand increased 4% year-over-year, positively impacted by weather and the prior year economic impacts of COVID. Electricity generation from thermal coal has notably improved year-over-year as a result of higher natural gas prices and stronger overall electricity demand. This has positively impacted coal’s share of electricity generation, with a rise to approximately 22% for the six months ended June 30, 2021, while causing natural gas’s share to decline to approximately 36%. Stronger coal use has contributed to decreasing coal stockpile levels. Since December 2020, coal inventories have fallen by approximately 17 million tons. Through the six months ended June 30, 2021, utility consumption of PRB coal rose approximately 35% compared to the prior year period. The Company’s revenues for the three months ended June 30, 2021 increased compared to the same period in 2020 ($96.7 million) primarily due to the impact of higher sales volumes and higher seaborne thermal pricing. Revenues for the six months ended June 30, 2021 decreased compared to the same period in 2020 ($98.2 million) primarily due to lower realized prices and lower sales volumes. Results from continuing operations, net of income taxes for the three months ended June 30, 2021 increased compared to the same period in the prior year ($1,522.3 million) primarily due to the asset impairment charges recorded in the prior year period ($ 1,418.1 million) and the favorable revenue variance described above. Results from continuing operations, net of income taxes for the six months ended June 30, 2021 increased compared to the same period in the prior year ($1,573.9 million) primarily due to the asset impairment charges recorded in the prior year period ($ 1,418.1 million), lower operating costs and expenses driven by the sales volume decline as well as production efficiencies and other cost improvements ($141.8 million) and lower depreciation, depletion and amortization ($48.9 million). These favorable variances were offset by the unfavorable revenue variance described above and increased interest expense ($30.4 million) primarily resulting from fees and higher borrowing rates related to new debt arrangements entered into during the first quarter of 2021. Adjusted EBITDA for the three and six months ended June 30, 2021 reflected a year-over-year increase of $98.7 million and $123.0 million, respectively. As of June 30, 2021, the Company’s available liquidity was approximately $564 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting the Company’s available liquidity. 34 Table of Contents Tons Sold The following table presents tons sold by operating segment: Three Months Ended June 30, (Decrease ) Increase to Volumes Six Months Ended June 30, (Decrease ) Increase to Volumes 2021 2020 Tons % 2021 2020 Tons % (Tons in millions) (Tons in millions) Seaborne Thermal Mining 4.1 4.6 (0.5) (11) % 8.2 9.2 (1.0) (11) % Seaborne Metallurgical Mining 1.4 1.1 0.3 27 % 2.4 3.1 (0.7) (23) % Powder River Basin Mining 22.5 17.9 4.6 26 % 43.2 41.4 1.8 4 % Other U.S. Thermal Mining 3.9 3.8 0.1 3 % 7.8 8.7 (0.9) (10) % Total tons sold from mining segments 31.9 27.4 4.5 16 % 61.6 62.4 (0.8) (1) % Corporate and Other 0.9 0.9 — — % 1.4 1.5 (0.1) (7) % Total tons sold 32.8 28.3 4.5 16 % 63.0 63.9 (0.9) (1) % Supplemental Financial Data The following table presents supplemental financial data by operating segment: Three Months Ended June 30, Increase (Decrease) Six Months Ended June 30, Increase (Decrease) 2021 2020 $ % 2021 2020 $ % Revenues per Ton - Mining Operations (1) Seaborne Thermal $ 46.92 $ 35.10 $ 11.82 34 % $ 45.15 $ 39.58 $ 5.57 14 % Seaborne Metallurgical 85.48 86.80 (1.32) (2) % 86.31 92.61 (6.30) (7) % Powder River Basin 11.06 11.45 (0.39) (3) % 11.04 11.40 (0.36) (3) % Other U.S. Thermal 40.70 39.81 0.89 2 % 39.75 39.49 0.26 1 % Costs per Ton - Mining Operations (1)(2) Seaborne Thermal $ 29.61 $ 29.19 $ 0.42 1 % $ 32.97 $ 30.56 $ 2.41 8 % Seaborne Metallurgical 104.24 120.72 (16.48) (14) % 106.51 115.00 (8.49) (7) % Powder River Basin 9.04 9.26 (0.22) (2) % 9.29 9.84 (0.55) (6) % Other U.S. Thermal 29.57 31.22 (1.65) (5) % 29.47 31.31 (1.84) (6) % Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) Seaborne Thermal $ 17.31 $ 5.91 $ 11.40 193 % $ 12.18 $ 9.02 $ 3.16 35 % Seaborne Metallurgical (18.76) (33.92) 15.16 45 % (20.20) (22.39) 2.19 10 % Powder River Basin 2.02 2.19 (0.17) (8) % 1.75 1.56 0.19 12 % Other U.S. Thermal 11.13 8.59 2.54 30 % 10.28 8.18 2.10 26 % (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; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. 35 Table of Contents Revenues The following table presents revenues by reporting segment: Three Months Ended June 30, Increase (Decrease) to Revenues Six Months Ended June 30, Increase (Decrease) to Revenues 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 194.1 $ 162.0 $ 32.1 20 % $ 370.5 $ 363.1 $ 7.4 2 % Seaborne Metallurgical Mining 121.0 91.6 29.4 32 % 208.5 284.8 (76.3) (27) % Powder River Basin Mining 248.6 205.8 42.8 21 % 477.0 472.4 4.6 1 % Other U.S. Thermal Mining 162.1 152.0 10.1 7 % 311.4 344.3 (32.9) (10) % Corporate and Other (2.4) 15.3 (17.7) (116) % 7.3 8.3 (1.0) (12) % Revenues $ 723.4 $ 626.7 $ 96.7 15 % $ 1,374.7 $ 1,472.9 $ (98.2) (7) % Seaborne Thermal Mining. Segment revenues increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year due to favorable realized coal pricing (three months, $46.6 million; six months, $40.9 million), offset by unfavorable volume and mix variances (three months, $14.5 million; six months, $33.5 million). Seaborne Metallurgical Mining. Segment revenues increased during the three months ended June 30, 2021 compared to the same period in the prior year due to favorable volume and mix variances ($33.2 million), partially offset by unfavorable realized coal pricing ($3.8 million). Segment revenues decreased during the six months ended June 30, 2021 compared to the same period in the prior year due to unfavorable volume and mix variances ($66.7 million) and unfavorable realized coal pricing ($9.6 million). The unfavorable volume variances resulted from the Shoal Creek Mine being idled through the first half of 2021, the Metropolitan Mine being idled through the first quarter of 2021 and the closure of the Millennium Mine during the second quarter of 2020. These unfavorable volume variances were partially offset by improved demand at the Coppabella and Moorvale Mines. Powder River Basin Mining. Segment revenues increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year primarily due to increased demand (three months, $47.3 million; six months, $15.8 million), partially offset by unfavorable realized coal pricing (three months, $4.5 million; six months, $11.2 million). Other U.S. Thermal Mining. Segment revenues increased during the three months ended June 30, 2021 compared to the same period in the prior year due to favorable realized pricing ($5.9 million) and higher demand ($4.2 million). Segment revenues decreased during the six months ended June 30, 2021 compared to the same period in the prior year due to primarily due to lower demand ($38.0 million), partially offset by favorable realized pricing ($5.1 million). Corporate and Other. Segment revenues decreased during the three months ended June 30, 2021 compared to the same period in the prior year primarily due to lower results from trading activities. 36 Table of Contents Adjusted EBITDA The following table presents Adjusted EBITDA for each of the Company’s reporting segments: Three Months Ended June 30, Increase to Segment Adjusted EBITDA Six Months Ended June 30, Increase to Segment Adjusted EBITDA 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 71.4 $ 27.7 $ 43.7 158 % $ 99.9 $ 82.8 $ 17.1 21 % Seaborne Metallurgical Mining (26.4) (36.1) 9.7 27 % (48.8) (68.8) 20.0 29 % Powder River Basin Mining 45.5 39.3 6.2 16 % 75.6 64.7 10.9 17 % Other U.S. Thermal Mining 44.3 32.9 11.4 35 % 80.5 71.4 9.1 13 % Corporate and Other (12.7) (40.4) 27.7 69 % (24.0) (89.9) 65.9 73 % Adjusted EBITDA (1) $ 122.1 $ 23.4 $ 98.7 422 % $ 183.2 $ 60.2 $ 123.0 204 % (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 increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year as a result of higher realized net coal pricing (three months, $42.9 million; six months, $37.6 million) and cost improvements across the operations and product mix (three months, $27.2 million; six months, $33.6 million). The increases were partially offset by unfavorable foreign currency impacts (three months, $9.7 million; six months, $26.7 million) and unfavorable volume variances (three months, $9.7 million; six months, $23.4 million). Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year due to favorable volume variances (three months, $18.0 million; six months, $13.4 million) and cost improvements at certain mines (three months, $12.0 million; six months, $42.0 million), offset by unfavorable foreign currency impacts (three months, $15.0 million; six months, $40.3 million). Powder River Basin Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year due to favorable mine sequencing impacts (three months, $21.8 million; six months, $27.5 million) and favorable volume variances (three months, $9.9 million). The increases were offset by higher costs for materials, services, repairs and labor (three months, $12.5 million; six months, $5.9 million) and the unfavorable impacts of higher commodity pricing (three months, $10.3 million; six months, $10.2 million). Other U.S. Thermal Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year due to favorable volume variances (three months, $15.0 million; six months, $16.9 million) and favorable mine sequencing impacts (three months, $10.0 million; six months, $9.9 million), offset by the unfavorable impacts of higher commodity pricing (three months, $7.9 million; six months, $9.5 million) and higher costs for materials, services, repairs and labor (three months, $7.3 million; six months, $4.9 million). 37 Table of Contents Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: Three Months Ended June 30, Increase to Adjusted EBITDA Six Months Ended June 30, Increase (Decrease) to Adjusted EBITDA 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Middlemount (1) $ (4.1) $ (6.4) $ 2.3 36 % $ (6.4) $ (16.1) $ 9.7 60 % Resource management activities (2) 3.9 0.8 3.1 388 % 4.3 8.8 (4.5) (51) % Selling and administrative expenses (21.4) (25.2) 3.8 15 % (43.1) (50.1) 7.0 14 % Other items, net (3) 8.9 (9.6) 18.5 193 % 21.2 (32.5) 53.7 165 % Corporate and Other Adjusted EBITDA $ (12.7) $ (40.4) $ 27.7 69 % $ (24.0) $ (89.9) $ 65.9 73 % (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 $11.1 million and $8.8 million during the three months ended June 30, 2021 and 2020, respectively, and $22.8 million and $13.2 million during the six months ended June 30, 2021 and 2020, 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 the Company’s other commercial activities. The increase in Corporate and Other Adjusted EBITDA during the three and six months ended June 30, 2021 compared to the same periods in the prior year was driven by lower postretirement healthcare costs (three months, $11.2 million; six months, $22.4 million) primarily due to changes made to one of the Company’s postretirement health care benefit plans announced in 2020; lower containment and holding costs for the Company’s North Goonyella Mine (three months, $8.2 million; six months, $14.4 million); favorable trading results (six months, $11.8 million); a favorable variance in Middlemount’s results due to the combined impact of improved production and cost improvements; and favorable corporate hedging results (six months, $6.2 million). 38 Table of Contents Loss From Continuing Operations, Net of Income Taxes The following table presents loss from continuing operations, net of income taxes: Three Months Ended June 30, Increase (Decrease) to Income Six Months Ended June 30, Increase (Decrease) to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Adjusted EBITDA (1) $ 122.1 $ 23.4 $ 98.7 422 % $ 183.2 $ 60.2 $ 123.0 204 % Depreciation, depletion and amortization (77.1) (88.3) 11.2 13 % (145.4) (194.3) 48.9 25 % Asset retirement obligation expenses (15.1) (14.1) (1.0) (7) % (31.0) (31.7) 0.7 2 % Restructuring charges (2.1) (16.5) 14.4 87 % (4.2) (23.0) 18.8 82 % Transaction costs related to joint ventures — (12.9) 12.9 100 % — (17.1) 17.1 100 % Asset impairment — (1,418.1) 1,418.1 100 % — (1,418.1) 1,418.1 100 % Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 0.5 0.4 0.1 25 % 2.0 1.1 0.9 82 % Interest expense (45.4) (34.3) (11.1) (32) % (97.8) (67.4) (30.4) (45) % Net gain on early debt extinguishment 11.8 — 11.8 n.m. 15.3 — 15.3 n.m. Interest income 1.3 2.4 (1.1) (46) % 2.8 5.5 (2.7) (49) % Unrealized (losses) gains on economic hedges (23.7) 7.0 (30.7) (439) % (25.6) 4.8 (30.4) (633) % Unrealized (losses) gains on non-coal trading derivative contracts (1.2) 2.8 (4.0) (143) % (8.8) 2.9 (11.7) (403) % Take-or-pay contract-based intangible recognition 1.1 2.7 (1.6) (59) % 2.2 5.3 (3.1) (58) % Income tax benefit (provision) 4.8 0.2 4.6 2,300 % 6.6 (2.8) 9.4 336 % Loss from continuing operations, net of income taxes $ (23.0) $ (1,545.3) $ 1,522.3 99 % $ (100.7) $ (1,674.6) $ 1,573.9 94 % (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: Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ (26.9) $ (20.5) $ (6.4) (31) % $ (48.0) $ (42.7) $ (5.3) (12) % Seaborne Metallurgical Mining (17.4) (20.5) 3.1 15 % (33.9) (45.3) 11.4 25 % Powder River Basin Mining (10.3) (28.3) 18.0 64 % (19.9) (63.5) 43.6 69 % Other U.S. Thermal Mining (16.0) (15.6) (0.4) (3) % (33.2) (37.0) 3.8 10 % Corporate and Other (6.5) (3.4) (3.1) (91) % (10.4) (5.8) (4.6) (79) % Total $ (77.1) $ (88.3) $ 11.2 13 % $ (145.4) $ (194.3) $ 48.9 25 % 39 Table of Contents Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its mining segments: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Seaborne Thermal Mining $ 2.47 $ 2.08 $ 2.17 $ 1.99 Seaborne Metallurgical Mining 1.03 1.81 1.02 2.38 Powder River Basin Mining 0.24 0.80 0.24 0.79 Other U.S. Thermal Mining 1.17 0.96 1.15 1.02 Depreciation, depletion and amortization expense decreased during the three and six months ended June 30, 2021 compared to the same periods in the prior year primarily due to the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 (three months, $18.8 million; six months, $44.0 million). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three and six months ended June 30, 2021 compared to the same periods in the prior year reflects the volume and mix variances which impacted the Company’s revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the three and six months ended June 30, 2021 compared to the same periods in the prior year reflects the asset impairment recorded during the second quarter of 2020. Restructuring Charges. Restructuring charges decreased during the three and six months ended June 30, 2021 compared to the same periods in the prior year as the result of workforce reductions made across the organization during the prior year. Transaction Costs Related to Joint Ventures. The charges recorded during the prior year period related to the proposed PRB Colorado joint venture with Arch Resources, Inc. which was terminated during the third quarter of 2020. Asset Impairment. During the three and six months ended June 30, 2020, the Company recognized $1,418.1 million in aggregate asset impairment charges related to the fair value of its North Antelope Rochelle Mine in its Powder River Basin Mining segment as discussed in Note 8. “Property, Plant, Equipment and Mine Development” to the accompanying unaudited condensed consolidated financial statements. Interest Expense. Interest expense increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year as the result of a series of refinancing transactions completed by the Company during the first quarter of 2021 as described in Note 11. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements. Net Gain on Early Debt Extinguishment. The gain recognized during the three and six months ended June 30, 2021 was primarily related to debt retirements made through various open market purchases during the second quarter of 2021 and the senior notes exchange completed during the first quarter of 2021 as further discussed in Note 11. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements. 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 unaudited condensed consolidated financial statements. Unrealized (Losses) Gains on Non-Coal Trading Derivative Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge foreign currency option contracts. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Income Tax Benefit (Provision) . The increase in the income tax benefit for the three months ended June 30, 2021 compared to the same period in the prior year was primarily due to differences in forecasted taxable income and a decrease in the provision related to the remeasurement of foreign income tax accounts. The increase in the income tax benefit for the six months ended June 30, 2021 compared to the same period in the prior year was primarily due to differences in forecasted 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 unaudited condensed consolidated financial statements for additional information. 40 Table of Contents Net Loss Attributable to Common Stockholders The following table presents net loss attributable to common stockholders: Three Months Ended June 30, Increase to Income Six Months Ended June 30, Increase to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Loss from continuing operations, net of income taxes $ (23.0) $ (1,545.3) $ 1,522.3 99 % $ (100.7) $ (1,674.6) $ 1,573.9 94 % Loss from discontinued operations, net of income taxes (2.3) (2.3) — — % (4.3) (4.5) 0.2 4 % Net loss (25.3) (1,547.6) 1,522.3 98 % (105.0) (1,679.1) 1,574.1 94 % Less: Net income (loss) attributable to noncontrolling interests 3.3 (3.4) 6.7 197 % 3.7 (5.2) 8.9 171 % Net loss attributable to common stockholders $ (28.6) $ (1,544.2) $ 1,515.6 98 % $ (108.7) $ (1,673.9) $ 1,565.2 94 % Diluted Earnings per Share (EPS) The following table presents diluted EPS: Three Months Ended June 30, Increase to EPS Six Months Ended June 30, Increase to EPS 2021 2020 $ % 2021 2020 $ % Diluted EPS attributable to common stockholders: Loss from continuing operations $ (0.26) $ (15.76) $ 15.50 98 % $ (1.05) $ (17.12) $ 16.07 94 % Loss from discontinued operations (0.02) (0.02) — — % (0.04) (0.04) — — % Net loss attributable to common stockholders $ (0.28) $ (15.78) $ 15.50 98 % $ (1.09) $ (17.16) $ 16.07 94 % 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 101.2 million and 97.9 million for the three months ended June 30, 2021 and 2020, respectively, and 99.8 million and 97.5 million for the six months ended June 30, 2021 and 2020, respectively. 41 Table of Contents Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as loss from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below. Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (Dollars in millions) Loss from continuing operations, net of income taxes $ (23.0) $ (1,545.3) $ (100.7) $ (1,674.6) Depreciation, depletion and amortization 77.1 88.3 145.4 194.3 Asset retirement obligation expenses 15.1 14.1 31.0 31.7 Restructuring charges 2.1 16.5 4.2 23.0 Transaction costs related to joint ventures — 12.9 — 17.1 Asset impairment — 1,418.1 — 1,418.1 Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates (0.5) (0.4) (2.0) (1.1) Interest expense 45.4 34.3 97.8 67.4 Net gain on early debt extinguishment (11.8) — (15.3) — Interest income (1.3) (2.4) (2.8) (5.5) Unrealized losses (gains) on economic hedges 23.7 (7.0) 25.6 (4.8) Unrealized losses (gains) on non-coal trading derivative contracts 1.2 (2.8) 8.8 (2.9) Take-or-pay contract-based intangible recognition (1.1) (2.7) (2.2) (5.3) Income tax (benefit) provision (4.8) (0.2) (6.6) 2.8 Total Adjusted EBITDA $ 122.1 $ 23.4 $ 183.2 $ 60.2 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: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (Dollars in millions) Operating costs and expenses $ 611.4 $ 556.3 $ 1,194.0 $ 1,335.8 Unrealized (losses) gains on non-coal trading derivative contracts (1.2) 2.8 (8.8) 2.9 Take-or-pay contract-based intangible recognition 1.1 2.7 2.2 5.3 Net periodic benefit (credit) costs, excluding service cost (8.7) 2.7 (17.4) 5.5 Total Reporting Segment Costs $ 602.6 $ 564.5 $ 1,170.0 $ 1,349.5 42 Table of Contents The following table presents Reporting Segment Costs by reporting segment: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (Dollars in millions) Seaborne Thermal Mining $ 122.7 $ 134.3 $ 270.6 $ 280.3 Seaborne Metallurgical Mining 147.4 127.7 257.3 353.6 Powder River Basin Mining 203.1 166.5 401.4 407.7 Other U.S. Thermal Mining 117.8 119.1 230.9 272.9 Corporate and Other 11.6 16.9 9.8 35.0 Total Reporting Segment Costs $ 602.6 $ 564.5 $ 1,170.0 $ 1,349.5 The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment: Three Months Ended June 30, 2021 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 4.1 1.4 22.5 3.9 Revenues $ 194.1 $ 121.0 $ 248.6 $ 162.1 Reporting Segment Costs 122.7 147.4 203.1 117.8 Adjusted EBITDA $ 71.4 $ (26.4) $ 45.5 $ 44.3 Revenues per Ton $ 46.92 $ 85.48 $ 11.06 $ 40.70 Costs per Ton 29.61 104.24 9.04 29.57 Adjusted EBITDA Margin per Ton $ 17.31 $ (18.76) $ 2.02 $ 11.13 Three Months Ended June 30, 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 4.6 1.1 17.9 3.8 Revenues $ 162.0 $ 91.6 $ 205.8 $ 152.0 Reporting Segment Costs 134.3 127.7 166.5 119.1 Adjusted EBITDA $ 27.7 $ (36.1) $ 39.3 $ 32.9 Revenues per Ton $ 35.10 $ 86.80 $ 11.45 $ 39.81 Costs per Ton 29.19 120.72 9.26 31.22 Adjusted EBITDA Margin per Ton $ 5.91 $ (33.92) $ 2.19 $ 8.59 43 Table of Contents Six Months Ended June 30, 2021 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 8.2 2.4 43.2 7.8 Revenues $ 370.5 $ 208.5 $ 477.0 $ 311.4 Reporting Segment Costs 270.6 257.3 401.4 230.9 Adjusted EBITDA $ 99.9 $ (48.8) $ 75.6 $ 80.5 Revenues per Ton $ 45.15 $ 86.31 $ 11.04 $ 39.75 Costs per Ton 32.97 106.51 9.29 29.47 Adjusted EBITDA Margin per Ton $ 12.18 $ (20.20) $ 1.75 $ 10.28 Six Months Ended June 30, 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 9.2 3.1 41.4 8.7 Revenues $ 363.1 $ 284.8 $ 472.4 $ 344.3 Reporting Segment Costs 280.3 353.6 407.7 272.9 Adjusted EBITDA $ 82.8 $ (68.8) $ 64.7 $ 71.4 Revenues per Ton $ 39.58 $ 92.61 $ 11.40 $ 39.49 Costs per Ton 30.56 115.00 9.84 31.31 Adjusted EBITDA Margin per Ton $ 9.02 $ (22.39) $ 1.56 $ 8.18 Free Cash Flow is defined as net cash used in 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. Six Months Ended June 30, 2021 2020 (Dollars in millions) Net cash used in operating activities $ (22.8) $ (53.1) Net cash used in investing activities (82.6) (115.6) Free Cash Flow $ (105.4) $ (168.7) Regulatory Update Other than as described in the following section, there were no significant changes to the Company’s regulatory matters subsequent to December 31, 2020. Information regarding the Company’s regulatory matters is outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2020. Regulatory Matters - U.S. Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect the Company’s U.S. coal mining operations both directly and indirectly. 44 Table of Contents The CAA requires the United States Environmental Protection Agency (EPA) to review national ambient air quality standards (NAAQS) every five years to determine whether revision to current standards are appropriate. As part of this recurring review process, the EPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect. Fifteen states and other petitioners have filed a petition for review of the rule in the D.C. Circuit. The litigation is currently in abeyance following a motion filed by the EPA to allow for review of the standards. The EPA also proposed in 2020 to retain the particulate matter (PM) standards last revised in 2012. 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. This rule has also been challenged in the D.C. Circuit by several states and environmental organizations. The case is currently in abeyance following a motion filed by the EPA to allow for review of the standards. 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 other NAAQS for nitrogen dioxide (NO 2 ) and sulfur dioxide (SO 2 ), although there is no significant pending EPA rulemaking with respect to those pollutants. 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). The EPA subsequently proposed to repeal the CPP and in August 2018 issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule. In June 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction (BSER). The EPA’s final rule also revises certain 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 the Company, filed a motion to dismiss, which the court granted in September 2019. Numerous petitions for review challenging the ACE Rule were filed in the D.C. Circuit and subsequently consolidated. In January 2021, a 3-judge panel of the D.C. Circuit vacated and remanded the ACE Rule to the EPA, including its repeal of the CPP and amendments to the implementing regulations that extended the compliance timeline. Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule . In 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. In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in nitrogen oxide emissions beginning in 2017 in 22 states subject to CSAPR. In October 2020, the EPA proposed a rule to address a previous D.C. Circuit remand of the CSAPR Update Rule. On March 15, 2021, the EPA signed a final rule which imposed further reductions of NOx emmissions in 12 states while determining that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. In order to implement reductions in the 12 identified states, the EPA issued Federal Implementation Plans to lower state ozone season NOx budgets in 2021 to 2024, although limited emission trading can be used for compliance. Mercury and Air Toxic Standards (MATS) . The EPA published the final MATS rule in the Federal Register in 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. 45 Table of Contents In 2020, the EPA issued a final rule reversing a prior finding and determined that it is not “appropriate and necessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants. 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 and placed in abeyance. CWA Definition of “Waters of the United States” . In January 2020 the EPA and the Army Corps of Engineers (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. The Navigable Waters Protection Rule is currently in effect in all fifty states, but on June 9, 2021, the EPA and the Corps announced their intent to initiate a new rulemaking proceeding to replace the rule with a new definition of “Waters of the United States.” Litigation over the 2020 Navigable Waters Protection Rule remains pending in several federal district courts. 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. Safe Work Australia (SWA). As part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) Workplace Exposure Standard (WES) for carbon dioxide (CO 2 ) in Australian coal mines from 12,500 ppm to 5,000 ppm. Currently there is a separate TWA for CO 2 in coal mines however SWA proposes to remove this to align with a general industry standard. If implemented, the change has the potential to affect underground mines operating in CO 2 rich coal seams, including the primary coal seam of the Company’s Metropolitan Mine. Importantly, a minimum three-year transition period applies for any change to standards. Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021. On February 25, 2021 the Commonwealth Government introduced the Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021 into Parliament, which proposes amendments to the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) following the release of the Final Report of the Independent Review of the Act undertaken by Professor Graeme Samuel (the Samuel Review) that made 38 recommendations for short and long-term reforms, and ultimately calls for a complete overhaul of the existing legislative framework by 2022, to be undertaken in several tranches, with a strong focus on the setting of National Environmental Standards, assurance and compliance, data availability and management, and indigenous engagement. The bill responds to some of the recommendations for immediate reform made in the Samuel Review, and seeks to: establish a framework for the making, varying, revoking and application of National Environmental Standards; apply the National Environmental Standards to bilateral agreements with States and Territories; and establish an Environment Assurance Commissioner to monitor and audit bilateral agreements and other processes under the EPBC Act. The bill passed the Australian Parliament’s House of Representatives in June 2021 and will now be considered by the Australian Senate during its August sittings. Native Title and Cultural Heritage. On February 3, 2021 the Native Title Act 1993 was amended largely directed at improving the efficiency of the native title system for all parties. The amendments confirm the validity of most section 31 right to negotiate agreements which might be invalid because of non-execution by any of the persons comprising the registered native title claimant following the Full Federal Court's decision in McGlade v Registrar National Native Title Tribunal. Other significant amendments include that: during the right to negotiate process the parties to section 31 agreements are now required to notify the National Native Title Tribunal of the existence of any ancillary agreements; new section 47C allows historical extinguishment to be disregarded on park areas including extinguishment by public works; and new section 24MD(6B)(f) creates a new 8 month objection period for the creation of a right to mine for the purpose of an infrastructure facility associated with mining and to some compulsory acquisitions of native title. Global Climate In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no legislation directly affecting fossil fuel-fired powerplants has been signed into law. Congress did include climate legislation, the American Innovation and Manufacturing Act of 2020, within a large appropriations bill for the 2021 fiscal year. This legislation was enacted in December, 2020, and will require phasedown of the production and use of hydrofluorocarbons (HFCs) in the United States. While it is possible that the U.S. will adopt broader legislation in the future, the timing and specific requirements of any such legislation are uncertain. 46 Table of Contents 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 U.S. Supreme Court ruling in Massachusetts v. EPA, 549 U.S. 497 (2007) the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” As described above, however, the EPA’s rules affecting existing fossil-fuel fired power plants (i.e. the ACE Rule and the EPA’s repeal of the CPP) were vacated and remanded back to the EPA by the D.C. Circuit Court of Appeals. Greenhouse gas requirements for new, reconstructed and modified fossil fuel fired power plants remain in effect. Several changes in the New Source Review (NSR) program, a permitting plan under the CAA for new source construction and major modifications, have also been issued through guidance and rulemaking as described under “Regulatory Matters – U.S.” in the Company’s Annual Report on Form 10-K. The NSR program provides for the pre-construction review of new, reconstructed and modified stationary sources and results in determinations concerning the emission control technology that must be installed and operated at a source. Clean Air Act standards, known as new source performance standards, generally serve as a “floor” level of control for sources subject to NSR review; the final level of control is determined through the permitting process. In certain cases, performance standards or controls regarding greenhouse gas emissions may be required through the NSR process. 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. 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. Separately, California has committed through Executive Order B-55-18 and SB 100 to 100 percent “clean energy” by 2045 and the state of Washington has passed legislation to commit to carbon neutrality by 2050. 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. Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and Peabody regularly discloses in its annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by the Company in the U.S. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal. 47 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. In January 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 April 2021, the U.S. announced its own Nationally Determined Contribution (NDC) with respect to the Paris Agreement. The NDC is voluntary and would aim to cut carbon dioxide output by 50% to 52% compared with 2005 levels by 2030. Recently, the U.S. has announced the goal of a completely emissions-free power grid by 2035, but has not provided specificity for a regulatory framework to achieve that goal. The Company anticipates a series of executive actions and/or orders from the current presidential administration aimed at curbing emission levels as well as associated rulemaking using the CAA and potentially other statutory authorities. 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 has not formally committed to net zero emissions by 2050 with the focus of energy policy on the use of technology to accelerate the development and commercialization of low and zero emissions technologies and 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 the Company 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, Peabody attempts to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that Peabody 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 its operations, financial condition or cash flow. The Company does not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on its results of operations, financial condition or cash flows. 48 Table of Contents Liquidity and Capital Resources Overview The Company’s primary source of cash is proceeds from the sale of its coal production to customers. The Company has also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s 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. The Company has 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 the Company’s debt and surety agreements, its 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. The Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its 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 its industry, many of which are beyond the Company’s control. The Company has presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds.” Liquidity As of June 30, 2021, the Company’s cash balances totaled $548.3 million, including approximately $366 million held by U.S. subsidiaries and $153 million held by Australian subsidiaries, approximately $102 million of which was held by the subsidiaries that conduct the operations of its Wilpinjong Mine. The remaining cash balance was held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by the Company’s 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. The Company’s available liquidity declined from $728.7 million as of December 31, 2020 to $564.1 million as of June 30, 2021. Available liquidity, which excluded $13.6 million of restricted cash as of June 30, 2021, was comprised of the following: June 30, 2021 December 31, 2020 (Dollars in millions) Cash and cash equivalents $ 548.3 $ 709.2 Credit facility availability 15.5 0.2 Accounts receivable securitization program availability 0.3 19.3 Total liquidity $ 564.1 $ 728.7 49 Table of Contents Indebtedness The Company’s total funded indebtedness (Indebtedness) as of June 30, 2021 and December 31, 2020 is presented in the table below. Debt Instrument (defined below, as applicable) June 30, 2021 December 31, 2020 (Dollars in millions) 6.000% Senior Secured Notes due March 2022 (2022 Notes) $ 29.5 $ 459.0 8.500% Senior Secured Notes due December 2024 (Peabody Notes) 156.3 — 10.000% Senior Secured Notes due December 2024 (Co-Issuer Notes) 193.9 — 6.375% Senior Secured Notes due March 2025 (2025 Notes) 482.6 500.0 Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) 206.0 — Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) 368.6 388.2 Revolving credit facility — 216.0 Finance lease obligations 32.3 27.3 Less: Debt issuance costs (51.1) (42.7) 1,418.1 1,547.8 Less: Current portion of long-term debt 94.0 44.9 Long-term debt $ 1,324.1 $ 1,502.9 The Company’s Indebtedness was significantly impacted subsequent to December 31, 2020 as a result of various agreements and transactions described below. Refinancing and Related Transactions During the fourth quarter of 2020 and the first quarter of 2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and certain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio. Such agreements and related activities are described below. Organizational Realignment In July and August 2020, the Company effected certain changes to its 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). In connection with the change in structure, the Company’s subsidiary which owns and operates its Wilpinjong Mine in Australia became a subsidiary of the Co-Issuers. The Co-Issuers and the Wilpinjong subsidiary were designated as unrestricted subsidiaries under the Company’s credit agreement (Credit Agreement) and its senior notes’ indenture (the Existing Indenture). In connection with these actions, the Company contributed $100.0 million to the Co-Issuers to provide the Wilpinjong Mine with operating liquidity and address its near-term capital needs. Surety Agreement In November 2020, the Company entered into a surety transaction support agreement (Surety Agreement) with the providers of 99% of its surety bond portfolio (Participating Sureties) to resolve previous collateral demands made by the Participating Sureties. In accordance with the Surety Agreement, the Company 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, the Company 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 the Company generates more than $100.0 million of free cash flow (as defined in the Surety Agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Further, the Participating Sureties have agreed to a standstill through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025), 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. The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties. 50 Table of Contents Refinancing Transactions On January 29, 2021 (the Settlement Date), the Company completed a series of transactions (collectively, the Refinancing Transactions) to, among other things, provide it with maturity extensions and covenant relief, while allowing it to maintain near-term 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 its existing debt agreements, as summarized below. Exchange Offer On the Settlement Date, the Company settled an exchange offer (Exchange Offer) pursuant to which $398.7 million aggregate principal amount of its 6.000% Senior Secured Notes due March 2022 (2022 Notes) were validly tendered, accepted by the Company 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 (Co-Issuer Notes), (b) $195.1 million aggregate principal amount of new 8.500% Senior Secured Notes due 2024 issued by Peabody (Peabody Notes), and (c) a cash payment of approximately $9.4 million. In connection with the settlement of the Exchange Offer, the Company also paid early tender premiums totaling $4.0 million in cash. Refer to Note 11. “Long-term Debt” for additional information associated with the Co-Issuer Notes and the Peabody Notes. As required under the Exchange Offer, the Company purchased $22.4 million of the Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest, during the first quarter of 2021 and recognized a related net gain on extinguishment of $3.5 million. Consent Solicitation Concurrently with the Exchange Offer, the Company 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, the Company 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 (Co-Issuer Term Loans, Co-Issuer Term Loan Agreement), (iii) Peabody entering into a letter of credit facility (the Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions). The Co-Issuer Term Loans mature on December 31, 2024 and bear interest at a rate of 10.00% per annum. On the Settlement Date, the Company entered into the Company LC Agreement with the revolving lenders party to the Credit Agreement, pursuant to which the Company obtained a $324.0 million letter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued. The commitments under the Company LC Agreement mature on December 31, 2024. Undrawn letters of credit under the 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, the Company amended the Credit Agreement to make certain changes in consideration of the 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. The Company LC Agreement requires that the Company’s 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, its subsidiaries and other unrestricted subsidiaries is excluded from the calculation. Liquidity calculated in this manner amounted to $444.9 million at June 30, 2021. 51 Table of Contents The indenture which governs the Peabody Notes and the Company LC Agreement allow the Company to make open market debt repurchases, subject to certain limitations, including, but not limited to: (i) the Company’s unrestricted subsidiaries’ liquidity must be greater than or equal to $200.0 million after giving effect to such repurchases and (ii) for every $4 of principal repurchased in any fiscal quarter, the Company must make an offer on a pro rata basis to purchase $1 of principal amount of debt from holders of the Peabody Notes and the priority lien obligations under the Company LC Agreement within 30 days of the end of such fiscal quarter at a price equal to the weighted average repurchase price paid over that quarter (Mandatory Repurchase Offer). Other Debt Financing The Refinancing Transactions did not significantly impact the Company’s existing senior secured term loan under the Credit Facility (Senior Secured Term Loan), or its $500.0 million of 6.375% senior secured notes due March 2025 (2025 Notes), but these debt instruments were impacted by subsequent financing transactions described below. 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. The senior secured notes require semi-annual interest payments each March 31 and September 30 until maturity. The Company’s debt agreements impose various restrictions and limits on certain categories of payments that the Company may make, such as those for dividends, investments, and stock repurchases. The Company is also subject to customary affirmative and negative covenants. The Company was compliant with all covenants under its debt agreements including the minimum liquidity covenant under the Company LC Agreement at June 30, 2021. Subsequent Financing Transactions Subsequent to the Refinancing Transactions, the Company completed a series of financing transactions intended to improve its capital structure. In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its common stock. Such sales are allowed using methods permissible under Rule 415 of the Securities Act. The shares are offered and sold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by a prospectus supplement dated June 4, 2021, relating to the offer and sale of the shares. During the three months ended June 30, 2021, the Company sold approximately 8.1 million shares for net cash proceeds of $65.1 million. Subsequent to June 30, 2021, the Company settled sales of an additional 2.7 million shares for net proceeds of $21.5 million. During the three months ended June 30, 2021, the Company retired $18.0 million of Peabody Notes, $17.4 million of 2025 Notes and $17.8 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $39.2 million. The Company recorded a gain on early debt extinguishment of $11.9 million, net of debt issuance costs and original issue discount related to the retired debt of $2.1 million. Also during the three months ended June 30, 2021, the Company completed multiple bilateral transactions with holders of the 2022 Notes in which the Company issued an aggregate 4.5 million shares of its common stock in exchange for $30.9 million aggregate principal amount of the 2022 Notes. Based upon the fair value of the Company’s common stock at the respective settlement dates, the Company recorded a net loss on early debt extinguishment of $0.1 million in connection with the transactions. The issuance of shares of common stock in exchange for the 2022 Notes was exempt from registration under the Securities Act, on the basis that the exchange was completed with existing holders of the Company’s securities, and no commission or other remuneration was paid or given for soliciting the exchange. The Company also reached agreements to retire an additional $49.5 million of aggregate principal, which will settle subsequent to June 30, 2021. This included $44.0 million of its Senior Secured Term Loan due 2025 and $1.5 million of 2025 Notes through similar open market purchases for an aggregate cost of $30.2 million, and by issuing an aggregate 0.5 million shares of its common stock in exchange for $4.0 million aggregate principal amount of the 2022 Notes in a similar manner noted above. Such amounts are reflected within the current portion of long-term debt in the accompanying condensed consolidated balance sheets at June 30, 2021. As a result of the Company’s open market purchases of its debt during the three months ended June 30, 2021, on July 7, 2021, the Company announced a Mandatory Repurchase Offer of up to $13.3 million of its 2024 Peabody Notes, at 73.840% of their aggregate accreted value, plus accrued and unpaid interest, and a concurrent repurchase offer of priority lien obligations under the Company LC Agreement. The offers expire on August 6, 2021, unless extended by the Company. 52 Table of Contents Considering the Refinancing Transactions and the subsequent financing transactions described above, the Company expects to incur approximately $190 million of interest expense, including approximately $40 million of non-cash interest expense, during the year ended December 31, 2021. Accounts Receivable Securitization Program As described in Note 16. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017 which currently matures in 2022. The Company intends to renew the facility prior to maturity. 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 utilized for letters of credit in support of other obligations. At June 30, 2021, the Company h a d no outstanding borrowings and $125.5 million of letters of credit issued under the program, which were primarily in support of portions of the Company’s reclamation obligations. The Company had $13.6 million of cash collateral posted under the Securitization Program at June 30, 2021 due to outstanding letters of credit temporarily exceeding the balance of eligible receivables at quarter-end. Capital Requirements For 2021, the Company is targeting capital expenditures of approximately $200 million, which includes approximately $100 million for ongoing extension projects primarily related to its Seaborne Thermal Mining segment. The Company has no substantial future payment requirements under U.S. federal coal reserve leases. Contractual Obligations There were no material changes to the Company’s contractual obligations from the information previously provided in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020. Cash Flows and Free Cash Flow The following table summarizes the Company’s cash flows for the six months ended June 30, 2021 and 2020, as reported in the accompanying unaudited condensed consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP. Six Months Ended June 30, 2021 2020 (Dollars in millions) Net cash used in operating activities $ (22.8) $ (53.1) Net cash used in investing activities (82.6) (115.6) Net cash (used in) provided by financing activities (41.9) 285.0 Net change in cash, cash equivalents and restricted cash (147.3) 116.3 Cash, cash equivalents and restricted cash at beginning of period 709.2 732.2 Cash, cash equivalents and restricted cash at end of period $ 561.9 $ 848.5 Net cash used in operating activities $ (22.8) $ (53.1) Net cash used in investing activities (82.6) (115.6) Free Cash Flow $ (105.4) $ (168.7) 53 Table of Contents Operating Activities. The decrease in net cash used in operating activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by a year-over-year increase in cash generated by Company’s mining operations, partially offset by an unfavorable change in net cash flows associated with its working capital ($67.2 million). Investing Activities. The decrease in net cash used in investing activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by lower advances to related parties and joint ventures, on a net basis ($34.8 million). Financing Activities. The decrease in net cash provided by financing activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by $300.0 million of revolving loan borrowings in the prior year, higher repayments of debt principal ($73.2 million) and payments for deferred financing costs ($22.5 million) in the current year, partially offset by $65.1 million proceeds from the issuance of common stock in the current year. Off-Balance-Sheet Arrangements In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At June 30, 2021, such instruments inc lude d $1,555.0 million of surety bonds and $435.4 million o f letters of credit. Such financial instruments provide support for its reclamation bonding requirements, lease obligations, insu rance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in its condensed consolidated balance sheets. As of June 30, 2021, 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 $ 1,379.0 $ 42.1 $ 87.3 $ 30.9 $ 15.7 $ 1,555.0 Letters of credit outstanding under letter of credit facility 206.0 90.4 7.1 5.0 — 308.5 Letters of credit outstanding under accounts receivable securitization program 104.5 16.6 4.4 — — 125.5 Other letters of credit — 1.4 — — — 1.4 1,689.5 150.5 98.8 35.9 15.7 1,990.4 Less: Letters of credit in support of surety bonds (4) (303.8) (29.7) — (1.2) — (334.7) Less: Cash collateral in support of surety bonds (4) (15.0) — — — — (15.0) Obligations supported, net $ 1,370.7 $ 120.8 $ 98.8 $ 34.7 $ 15.7 $ 1,640.7 (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. The Company has also posted $5.2 million in incremental collateral directly with the beneficiary that is not supported by a surety bond. Financial assurances associated with new reclamation bonding requirements, surety bonds or other obligations may require additional collateral in the form of cash or letters of credit causing a decline in the Company’s liquidity. 54 Table of Contents As described in Note 16. “Financial Instruments and Other Guarantees” in the accompanying unaudited condensed consolidated financial statements, the Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. 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. Self-bonding in the U.S. has become increasingly restricted in recent years, leading to the Company’s increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on its liquidity due to increased collateral requirements and surety and related fees. At June 30, 2021, the Company had total asset retirement obligations of $741.8 million which were backed by a combination of surety bonds, bank guarantees and letters of credit. Bonding requirement amounts may differ significantly from the re lated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s 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 16. “Financial Instruments and Other Guarantees” in the Company’s unaudited condensed consolidated financial statements for a discussion of its accounts receivable securitization program and guarantees and other financial instruments with off-balance-sheet risk. Critical Accounting Policies and Estimates The Company’s discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its financial statements, which have been prepared in accordance with U.S. GAAP. The Company is 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, the Company evaluates its estimates. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. At June 30, 2021, the Company identified certain assets with an aggregate carrying value of approximately $1.2 billion in its Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other segments whose recoverability is most sensitive to coal pricing, cost pressures, customer demand, customer concentration risk and future economic viability. The Company conducted a review of those assets for recoverability as of June 30, 2021 and determined that no impairment charges were necessary as of that date. The Company’s critical accounting policies are discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2020. The Company’s critical accounting policies remain unchanged at June 30, 2021. Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to the Company’s unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented. 55 Table of Contents