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. 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. 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. 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. 32 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 September 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. 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 September 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 September 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 September 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 September 30, 2021 Premium HCC (1) $ 408.50 $ 198.00 $ 263.66 $ 388.50 Premium PCI coal (1) 255.50 145.25 185.37 242.50 Newcastle index thermal coal (1) 203.20 140.08 166.17 203.20 API 5 thermal coal (1) 111.00 76.09 93.17 111.00 PRB 8,800 Btu/Lb coal (2) 24.00 12.50 14.49 24.00 Illinois Basin 11,500 Btu/Lb coal (2) 66.00 41.00 53.28 66.00 (1) Prices expressed per metric tonne. (2) Prices expressed per short ton. Within the global coal industry, supply and demand disruptions were widespread as the coronavirus (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 nine months ended September 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. Within the seaborne metallurgical coal market, a combination of robust steel production, decade-high steel margins and tight coal availability have driven Australian spot prices to record levels. China’s unofficial ban on Australian coal remains in place and continues to support delivered China prices well above those of all other markets as domestic, Mongolian and seaborne coal supply from other sources continues to lag overall demand. The high prices being paid by China are incentivizing producers in Russia, the U.S. and Canada to supply China with incremental volumes, providing opportunities for Australia to supply customers typically serviced by these countries. The supply response to the record prices remains muted sending metallurgical coal prices higher. The Company believes energy shortages in some markets present a risk to industrial activity but the underlying market fundamentals remain constructive. 33 Table of Contents Within the seaborne thermal coal market, a combination of tight supplies and elevated demand have driven Newcastle thermal coal pricing to record levels. China’s domestic thermal coal supply remains hampered by heightened safety inspections and mine suspensions, as well as flooding. Thermal electricity generation in China has been strong year-to-date, and the relaxation of China’s import controls combined with tight domestic supply has pushed import demand higher. Both India and China are experiencing rolling power outages, as multi-year low stockpile levels and high coal prices are pushing power plants into load shedding. In Europe, gas supply constraints and low wind generation have pushed standby coal plants to resume operation to help supply strong electricity demand. Despite the strong demand, the supply response has been muted, sending thermal coal prices higher. Heavy rains in Indonesia, rail issues in Russia, production issues in Colombia and hampered domestic supply in China have all combined to pressure the global thermal market. In the United States, overall electricity demand increased 3% year-over-year, positively impacted by weather and the prior year economic impacts of the COVID-19 pandemic. 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 23% for the nine months ended September 30, 2021, while causing natural gas’s share to decline to approximately 37%. Stronger coal use and a limited supply response in coal production has contributed to decreasing coal stockpile levels. Since December 2020, coal inventories have fallen by approximately 54 million tons, a 40% decline. Through the nine months ended September 30, 2021, utility consumption of PRB coal rose approximately 30% compared to the prior year period. 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 and third quarters of 2021, and continuing into the fourth 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 During July 2021, the Company executed transactions to sell its closed Millennium and Wilkie Creek Mines, which reduced its closed mine reclamation liabilities and associated costs. Both mines were sold for minimal cash consideration and gains of $26.1 million and $24.6 million, respectively, were recorded in connection with the sales. In September 2021, the Company reached a new collective bargaining agreement with the UMWA on behalf of the hourly workforce of its Shoal Creek Mine. The Company idled the mine in the fourth quarter of 2020 due to market conditions. During the idle period the Company undertook activities, including a preparation plant upgrade project, to increase productivity, lower costs and improve yields from the operation in the future. The Company expects to begin production at Shoal Creek Mine in the second half of the fourth quarter of 2021, with ramp up through the first quarter of 2022. The full workforce of the Metropolitan Mine, which was idled in December 2020, returned to the mine in May 2021. 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 fourth quarter of 2021. The underground workforce enterprise agreement expired in January 2021 and was renegotiated in October 2021. In October 2021, the Company announced changes to its postretirement health care benefit plan for certain represented retirees. Effective January 1, 2022, the Company will not provide medical coverage to certain existing retirees but will continue to offer a life insurance benefit to eligible retirees. As of September 30, 2021, the health care benefit obligation attributed to these certain existing retirees is approximately $160.0 million. The impact of the changes will reduce the Company’s postretirement benefit obligation during the fourth quarter of 2021. 34 Table of Contents Results of Operations Three and Nine Months Ended September 30, 2021 Compared to the Three and Nine Months Ended September 30, 2020 Summary The Company’s revenues for the three months ended September 30, 2021 increased compared to the same period in 2020 ($8.0 million) due to the impacts of higher seaborne thermal and metallurgical pricing and higher seaborne metallurgical volumes, offset by net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading ($222.3 million). Revenues for the nine months ended September 30, 2021 decreased compared to the same period in 2020 ($90.2 million) primarily due to the net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading ($249.5 million) and lower sales volumes, partially offset by higher seaborne thermal and metallurgical pricing. Results from continuing operations, net of income taxes for the three months ended September 30, 2021 increased compared to the same period in the prior year ($5.2 million) primarily due to improved results from equity affiliates ($26.4 million), net gains from asset disposals in the current year ($23.3 million) driven by the sale of the Millennium Mine, net gains on early debt extinguishments in the current year ($16.0 million), net mark-to-market losses on actuarially determined liabilities recorded in the prior year period ($13.0 million) and lower postretirement health care costs ($11.4 million). These favorable variances were offset by higher operating costs and expenses ($98.5 million). Results from continuing operations, net of income taxes for the nine months ended September 30, 2021 increased compared to the same period in the prior year ($1,579.1 million) primarily due to the asset impairment charges recorded in the prior year period ($ 1,418.1 million), lower operating costs and expenses driven by the sales volume decline as well as production efficiencies and other cost improvements ($43.3 million), lower depreciation, depletion and amortization ($43.2 million), improved results from equity affiliates ($37.1 million), lower postretirement health care costs ($34.3 million) and net gains on early debt extinguishments in the current year ($31.3 million). These favorable variances were offset by the unfavorable revenue variance described above and increased interest expense ($41.0 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 nine months ended September 30, 2021 reflected a year-over-year increase of $193.7 million and $316.7 million, respectively. As of September 30, 2021, the Company’s available liquidity was approximately $615 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. Tons Sold The following table presents tons sold by operating segment: Three Months Ended September 30, (Decrease ) Increase to Volumes Nine Months Ended September 30, (Decrease ) Increase to Volumes 2021 2020 Tons % 2021 2020 Tons % (Tons in millions) (Tons in millions) Seaborne Thermal Mining 4.5 4.6 (0.1) (2) % 12.7 13.8 (1.1) (8) % Seaborne Metallurgical Mining 1.5 1.1 0.4 36 % 3.9 4.2 (0.3) (7) % Powder River Basin Mining 22.7 23.6 (0.9) (4) % 65.9 65.0 0.9 1 % Other U.S. Thermal Mining 4.5 4.8 (0.3) (6) % 12.3 13.5 (1.2) (9) % Total tons sold from mining segments 33.2 34.1 (0.9) (3) % 94.8 96.5 (1.7) (2) % Corporate and Other 0.5 0.6 (0.1) (17) % 1.9 2.1 (0.2) (10) % Total tons sold 33.7 34.7 (1.0) (3) % 96.7 98.6 (1.9) (2) % 35 Table of Contents Supplemental Financial Data The following table presents supplemental financial data by operating segment: Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, Increase (Decrease) 2021 2020 $ % 2021 2020 $ % Revenues per Ton - Mining Operations (1) Seaborne Thermal $ 58.53 $ 35.28 $ 23.25 66 % $ 49.86 $ 38.14 $ 11.72 31 % Seaborne Metallurgical 119.98 71.88 48.10 67 % 99.18 87.16 12.02 14 % Powder River Basin 10.88 11.26 (0.38) (3) % 10.99 11.35 (0.36) (3) % Other U.S. Thermal 40.99 37.20 3.79 10 % 40.20 38.67 1.53 4 % Costs per Ton - Mining Operations (1)(2) Seaborne Thermal $ 35.09 $ 27.59 $ 7.50 27 % $ 33.72 $ 29.58 $ 4.14 14 % Seaborne Metallurgical 81.61 96.87 (15.26) (16) % 96.98 110.20 (13.22) (12) % Powder River Basin 9.25 7.93 1.32 17 % 9.28 9.15 0.13 1 % Other U.S. Thermal 30.99 26.52 4.47 17 % 30.02 29.60 0.42 1 % Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) Seaborne Thermal $ 23.44 $ 7.69 $ 15.75 205 % $ 16.14 $ 8.56 $ 7.58 89 % Seaborne Metallurgical 38.37 (24.99) 63.36 254 % 2.20 (23.04) 25.24 110 % Powder River Basin 1.63 3.33 (1.70) (51) % 1.71 2.20 (0.49) (22) % Other U.S. Thermal 10.00 10.68 (0.68) (6) % 10.18 9.07 1.11 12 % (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. Revenues The following table presents revenues by reporting segment: Three Months Ended September 30, Increase (Decrease) to Revenues Nine Months Ended September 30, Increase (Decrease) to Revenues 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 260.7 $ 163.0 $ 97.7 60 % $ 631.2 $ 526.1 $ 105.1 20 % Seaborne Metallurgical Mining 179.5 78.8 100.7 128 % 388.0 363.6 24.4 7 % Powder River Basin Mining 247.1 264.8 (17.7) (7) % 724.1 737.2 (13.1) (2) % Other U.S. Thermal Mining 184.6 179.8 4.8 3 % 496.0 524.1 (28.1) (5) % Corporate and Other (192.9) (15.4) (177.5) (1,153) % (185.6) (7.1) (178.5) (2,514) % Revenues $ 679.0 $ 671.0 $ 8.0 1 % $ 2,053.7 $ 2,143.9 $ (90.2) (4) % Seaborne Thermal Mining. Segment revenues increased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to favorable realized coal pricing (three months, $105.5 million; nine months, $144.8 million), offset by unfavorable volume and mix variances (three months, $7.8 million; nine months, $39.7 million). 36 Table of Contents Seaborne Metallurgical Mining. Segment revenues increased during the three months ended September 30, 2021 compared to the same period in the prior year due to favorable realized coal pricing ($67.0 million) and favorable volume and mix variances ($33.7 million). Segment revenues increased during the nine months ended September 30, 2021 compared to the same period in the prior year due to favorable realized coal pricing ($52.3 million), partially offset by unfavorable volume and mix variances ($27.9 million). The unfavorable volume variances resulted from the Shoal Creek Mine being idled through the first nine months 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 decreased during the three months ended September 30, 2021 compared to the same period in the prior year primarily due to decreased production ($9.7 million) and unfavorable realized coal pricing ($8.0 million). Segment revenues decreased during the nine months ended September 30, 2021 compared to the same period in the prior year primarily due to unfavorable realized coal pricing ($19.3 million), partially offset by increased demand ($6.2 million). Other U.S. Thermal Mining. Segment revenues increased during the three months ended September 30, 2021 compared to the same period in the prior year due to favorable realized pricing ($18.9 million), offset by lower volumes attributable to decreased production and rail performance issues ($14.1 million). Segment revenues decreased during the nine months ended September 30, 2021 compared to the same period in the prior year primarily due to lower volumes attributable to decreased production and rail performance issues ($52.0 million), partially offset by favorable realized pricing ($23.9 million). Corporate and Other. Segment revenues decreased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year primarily due to net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales and other financial trading (three months, $222.3 million; nine months, $249.5 million), partially offset by higher results from trading activities. Adjusted EBITDA The following table presents Adjusted EBITDA for each of the Company’s reporting segments: Three Months Ended September 30, Increase (Decrease) to Segment Adjusted EBITDA Nine Months Ended September 30, Increase (Decrease) to Segment Adjusted EBITDA 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 104.4 $ 35.3 $ 69.1 196 % $ 204.3 $ 118.1 $ 86.2 73 % Seaborne Metallurgical Mining 57.4 (27.3) 84.7 310 % 8.6 (96.1) 104.7 109 % Powder River Basin Mining 37.0 78.3 (41.3) (53) % 112.6 143.0 (30.4) (21) % Other U.S. Thermal Mining 45.1 51.6 (6.5) (13) % 125.6 123.0 2.6 2 % Corporate and Other 45.2 (42.5) 87.7 206 % 21.2 (132.4) 153.6 116 % Adjusted EBITDA (1) $ 289.1 $ 95.4 $ 193.7 203 % $ 472.3 $ 155.6 $ 316.7 204 % (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 months ended September 30, 2021 compared to the same period in the prior year as a result of higher realized net coal pricing ($97.5 million), partially offset by unfavorable mine sequencing impacts ($14.7 million), unfavorable sales volume variances ($5.1 million) and higher commodity pricing ($4.0 million). Segment Adjusted EBITDA increased during the nine months ended September 30, 2021 compared to the same period in the prior year as a result of higher realized net coal pricing ($133.2 million) and cost improvements across the operations and product mix ($21.3 million). The increases were partially offset by unfavorable volume variances ($29.1 million) and unfavorable foreign currency impacts ($28.7 million). Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to higher realized net coal pricing (three months, $62.3 million; nine months, $48.8 million), cost improvements at certain mines (three months, $23.1 million; nine months, $71.9 million) and favorable volume variances (three months, $3.5 million; nine months, $19.8 million), offset by unfavorable foreign currency impacts (three months, $2.2 million; nine months, $41.9 million). 37 Table of Contents Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to lower realized net coal pricing (three months, $12.6 million; nine months, $17.7 million), higher costs for materials, services, repairs and labor (three months, $12.6 million; nine months, $16.7 million) and the unfavorable impacts of higher commodity pricing (three months, $8.1 million; nine months, $18.1 million). The decreases were offset by favorable mine sequencing impacts (nine months, $16.5 million). Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2021 compared to the same period in the prior year due to higher costs for materials, services, repairs and labor ($12.9 million) and the unfavorable impacts of higher commodity pricing ($7.0 million), offset by higher realized net coal pricing ($17.9 million). Segment Adjusted EBITDA increased during the nine months ended September 30, 2021 compared to the same period in the prior year due to higher realized net coal pricing ($21.2 million) and favorable mine sequencing impacts ($16.9 million), offset by the unfavorable impacts of higher commodity pricing ($13.6 million). Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: Three Months Ended September 30, Increase (Decrease) to Adjusted EBITDA Nine Months Ended September 30, Increase (Decrease) to Adjusted EBITDA 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Middlemount (1) $ 9.3 $ (11.1) $ 20.4 184 % $ 2.9 $ (27.2) $ 30.1 111 % Resource management activities (2) (0.4) 1.0 (1.4) (140) % 3.9 9.8 (5.9) (60) % Selling and administrative expenses (21.1) (27.2) 6.1 22 % (64.2) (77.3) 13.1 17 % Other items, net (3) 57.4 (5.2) 62.6 1,204 % 78.6 (37.7) 116.3 308 % Corporate and Other Adjusted EBITDA $ 45.2 $ (42.5) $ 87.7 206 % $ 21.2 $ (132.4) $ 153.6 116 % (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 $17.9 million and $8.6 million during the three months ended September 30, 2021 and 2020, respectively, and $40.7 million and $21.8 million during the nine months ended September 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 nine months ended September 30, 2021 compared to the same periods in the prior year was driven by favorable trading results (three months, $27.4 million; nine months, $39.1 million); the gain recognized in the current year on the sale of the Company’s Millennium Mine (three and nine months, $26.1 million) as discussed in Note 14. “Other Events”; a favorable variance in Middlemount’s results due to the combined impacts of higher sales pricing, improved production and cost improvements; lower postretirement health care costs (three months, $11.2 million; nine months, $33.6 million) primarily due to changes made to one of the Company’s postretirement health care benefit plans announced in 2020; and lower containment and holding costs for the Company’s North Goonyella Mine (nine months, $15.4 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 September 30, Increase (Decrease) to Income Nine Months Ended September 30, Increase (Decrease) to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Adjusted EBITDA (1) $ 289.1 $ 95.4 $ 193.7 203 % $ 472.3 $ 155.6 $ 316.7 204 % Depreciation, depletion and amortization (77.9) (72.2) (5.7) (8) % (223.3) (266.5) 43.2 16 % Asset retirement obligation expenses (14.3) (14.3) — — % (45.3) (46.0) 0.7 2 % Restructuring charges (1.7) (8.1) 6.4 79 % (5.9) (31.1) 25.2 81 % Transaction costs related to joint ventures — (6.0) 6.0 100 % — (23.1) 23.1 100 % Asset impairment — — — n.m. — (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 6.4 0.5 5.9 1,180 % 8.4 1.6 6.8 425 % Interest expense (45.5) (34.9) (10.6) (30) % (143.3) (102.3) (41.0) (40) % Net gain on early debt extinguishment 16.0 — 16.0 n.m. 31.3 — 31.3 n.m. Interest income 1.4 1.6 (0.2) (13) % 4.2 7.1 (2.9) (41) % Net mark-to-market adjustment on actuarially determined liabilities — (13.0) 13.0 100 % — (13.0) 13.0 100 % Unrealized losses on derivative contracts related to forecasted sales (238.4) (16.1) (222.3) (1,381) % (264.0) (11.3) (252.7) (2,236) % Unrealized gains (losses) on foreign currency option contracts 0.6 0.7 (0.1) (14) % (8.2) 3.6 (11.8) (328) % Take-or-pay contract-based intangible recognition 1.0 1.5 (0.5) (33) % 3.2 6.8 (3.6) (53) % Income tax benefit (provision) 3.7 0.1 3.6 3,600 % 10.3 (2.7) 13.0 481 % Loss from continuing operations, net of income taxes $ (59.6) $ (64.8) $ 5.2 8 % $ (160.3) $ (1,739.4) $ 1,579.1 91 % (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 September 30, (Decrease) Increase to Income Nine Months Ended September 30, (Decrease) Increase to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ (25.8) $ (20.2) $ (5.6) (28) % $ (73.8) $ (62.9) $ (10.9) (17) % Seaborne Metallurgical Mining (19.6) (20.0) 0.4 2 % (53.5) (65.3) 11.8 18 % Powder River Basin Mining (11.9) (10.9) (1.0) (9) % (31.8) (74.4) 42.6 57 % Other U.S. Thermal Mining (17.0) (16.9) (0.1) (1) % (50.2) (53.9) 3.7 7 % Corporate and Other (3.6) (4.2) 0.6 14 % (14.0) (10.0) (4.0) (40) % Total $ (77.9) $ (72.2) $ (5.7) (8) % $ (223.3) $ (266.5) $ 43.2 16 % 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Seaborne Thermal Mining $ 2.20 $ 1.78 $ 2.18 $ 1.92 Seaborne Metallurgical Mining 1.14 1.83 1.06 2.24 Powder River Basin Mining 0.24 0.23 0.24 0.59 Other U.S. Thermal Mining 1.18 1.11 1.16 1.05 Depreciation, depletion and amortization expense decreased during the nine months ended September 30, 2021 compared to the same period 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 (nine months, $45.3 million). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three and nine months ended September 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 nine months ended September 30, 2021 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020. Restructuring Charges. Restructuring charges decreased during the three and nine months ended September 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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2021 was primarily related to debt retirements made through various open market purchases during the second and third quarters 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. Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The expense recorded during the three and nine months ended September 30, 2020 related to changes made to one of the Company’s postretirement health care benefit plans which triggered a remeasurement event. Unrealized Losses on Derivative Contracts Related to Forecasted Sales. Unrealized losses primarily relate to mark-to-market activity on derivatives related to forecasted sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Unrealized Gains (Losses) on Foreign Currency Option Contracts. Unrealized gains (losses) primarily relate to mark-to-market activity on 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 and nine months ended September 30, 2021 compared to the same periods in the prior year was primarily due to differences in forecasted taxable income and an increase in the benefit 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 September 30, Increase to Income Nine Months Ended September 30, Increase to Income 2021 2020 $ % 2021 2020 $ % (Dollars in millions) (Dollars in millions) Loss from continuing operations, net of income taxes $ (59.6) $ (64.8) $ 5.2 8 % $ (160.3) $ (1,739.4) $ 1,579.1 91 % Income (loss) from discontinued operations, net of income taxes 24.3 (2.3) 26.6 1,157 % 20.0 (6.8) 26.8 394 % Net loss (35.3) (67.1) 31.8 47 % (140.3) (1,746.2) 1,605.9 92 % Less: Net income (loss) attributable to noncontrolling interests 8.9 0.1 8.8 8,800 % 12.6 (5.1) 17.7 347 % Net loss attributable to common stockholders $ (44.2) $ (67.2) $ 23.0 34 % $ (152.9) $ (1,741.1) $ 1,588.2 91 % Income (Loss) from Discontinued Operations, Net of Income Taxes . The increase in the results from discontinued operations for the three and nine months ended September 30, 2021 compared to the same periods in the prior year was primarily due to the gain of $24.6 million recognized on the sale of the Wilkie Creek Mine. Refer to Note 14. “Other Events” to the accompanying unaudited condensed consolidated financial statements for additional information. Diluted Earnings per Share (EPS) The following table presents diluted EPS: Three Months Ended September 30, Increase to EPS Nine Months Ended September 30, Increase to EPS 2021 2020 $ % 2021 2020 $ % Diluted EPS attributable to common stockholders: Loss from continuing operations $ (0.60) $ (0.66) $ 0.06 9 % $ (1.65) $ (17.76) $ 16.11 91 % Income (loss) from discontinued operations 0.22 (0.03) 0.25 833 % 0.19 (0.07) 0.26 371 % Net loss attributable to common stockholders $ (0.38) $ (0.69) $ 0.31 45 % $ (1.46) $ (17.83) $ 16.37 92 % 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 114.9 million and 97.9 million for the three months ended September 30, 2021 and 2020, respectively, and 104.9 million and 97.6 million for the nine months ended September 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Dollars in millions) Loss from continuing operations, net of income taxes $ (59.6) $ (64.8) $ (160.3) $ (1,739.4) Depreciation, depletion and amortization 77.9 72.2 223.3 266.5 Asset retirement obligation expenses 14.3 14.3 45.3 46.0 Restructuring charges 1.7 8.1 5.9 31.1 Transaction costs related to joint ventures — 6.0 — 23.1 Asset impairment — — — 1,418.1 Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates (6.4) (0.5) (8.4) (1.6) Interest expense 45.5 34.9 143.3 102.3 Net gain on early debt extinguishment (16.0) — (31.3) — Interest income (1.4) (1.6) (4.2) (7.1) Net mark-to-market adjustment on actuarially determined liabilities — 13.0 — 13.0 Unrealized losses on derivative contracts related to forecasted sales 238.4 16.1 264.0 11.3 Unrealized (gains) losses on foreign currency option contracts (0.6) (0.7) 8.2 (3.6) Take-or-pay contract-based intangible recognition (1.0) (1.5) (3.2) (6.8) Income tax (benefit) provision (3.7) (0.1) (10.3) 2.7 Total Adjusted EBITDA $ 289.1 $ 95.4 $ 472.3 $ 155.6 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Dollars in millions) Operating costs and expenses $ 649.4 $ 550.9 $ 1,843.4 $ 1,886.7 Unrealized gains (losses) on foreign currency option contracts 0.6 0.7 (8.2) 3.6 Take-or-pay contract-based intangible recognition 1.0 1.5 3.2 6.8 Net periodic benefit (credit) costs, excluding service cost (8.6) 2.8 (26.0) 8.3 Total Reporting Segment Costs $ 642.4 $ 555.9 $ 1,812.4 $ 1,905.4 42 Table of Contents The following table presents Reporting Segment Costs by reporting segment: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (Dollars in millions) Seaborne Thermal Mining $ 156.3 $ 127.7 $ 426.9 $ 408.0 Seaborne Metallurgical Mining 122.1 106.1 379.4 459.7 Powder River Basin Mining 210.1 186.5 611.5 594.2 Other U.S. Thermal Mining 139.5 128.2 370.4 401.1 Corporate and Other 14.4 7.4 24.2 42.4 Total Reporting Segment Costs $ 642.4 $ 555.9 $ 1,812.4 $ 1,905.4 The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment: Three Months Ended September 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 4.5 1.5 22.7 4.5 Revenues $ 260.7 $ 179.5 $ 247.1 $ 184.6 Reporting Segment Costs 156.3 122.1 210.1 139.5 Adjusted EBITDA $ 104.4 $ 57.4 $ 37.0 $ 45.1 Revenues per Ton $ 58.53 $ 119.98 $ 10.88 $ 40.99 Costs per Ton 35.09 81.61 9.25 30.99 Adjusted EBITDA Margin per Ton $ 23.44 $ 38.37 $ 1.63 $ 10.00 Three Months Ended September 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 23.6 4.8 Revenues $ 163.0 $ 78.8 $ 264.8 $ 179.8 Reporting Segment Costs 127.7 106.1 186.5 128.2 Adjusted EBITDA $ 35.3 $ (27.3) $ 78.3 $ 51.6 Revenues per Ton $ 35.28 $ 71.88 $ 11.26 $ 37.20 Costs per Ton 27.59 96.87 7.93 26.52 Adjusted EBITDA Margin per Ton $ 7.69 $ (24.99) $ 3.33 $ 10.68 43 Table of Contents Nine Months Ended September 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 12.7 3.9 65.9 12.3 Revenues $ 631.2 $ 388.0 $ 724.1 $ 496.0 Reporting Segment Costs 426.9 379.4 611.5 370.4 Adjusted EBITDA $ 204.3 $ 8.6 $ 112.6 $ 125.6 Revenues per Ton $ 49.86 $ 99.18 $ 10.99 $ 40.20 Costs per Ton 33.72 96.98 9.28 30.02 Adjusted EBITDA Margin per Ton $ 16.14 $ 2.20 $ 1.71 $ 10.18 Nine Months Ended September 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 13.8 4.2 65.0 13.5 Revenues $ 526.1 $ 363.6 $ 737.2 $ 524.1 Reporting Segment Costs 408.0 459.7 594.2 401.1 Adjusted EBITDA $ 118.1 $ (96.1) $ 143.0 $ 123.0 Revenues per Ton $ 38.14 $ 87.16 $ 11.35 $ 38.67 Costs per Ton 29.58 110.20 9.15 29.60 Adjusted EBITDA Margin per Ton $ 8.56 $ (23.04) $ 2.20 $ 9.07 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. Nine Months Ended September 30, 2021 2020 (Dollars in millions) Net cash used in operating activities $ (18.4) $ (32.1) Net cash used in investing activities (119.7) (159.4) Free Cash Flow $ (138.1) $ (191.5) 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 United States Court of Appeals for the D.C. Circuit (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 these standards are not subject to a statutorily-required review until 2023 for NO 2 and 2024 for SO 2. 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 electric generation units (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. On October 29, 2021, the Supreme Court granted certiorari in four matters seeking review of the D.C. Circuit’s opinion invalidating the repeal of the CPP. In granting certiorari, the Supreme Court consolidated the cases to consider the breadth of the EPA’s scope pursuant to 42 U.S.C. Section 7411(d) of the CAA, specifically, whether it is limited to issuing standards for existing sources achievable through demonstrated technology and methods, or if it may also issue industry wide systems (such as cap and trade) which effectively seek to shift energy generation. The Company will continue to monitor the consolidated matters. 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 oxides (NO x ) 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 and in April 2021, the EPA published a final rule in the Federal Register which imposed further reductions of NO x emissions in 12 states that were subject to the original 2016 rule. 45 Table of Contents In the same rule, the EPA determined 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 NO x budgets in 2021 to 2024, although limited emission trading can be used for compliance and states have the ability to replace federal plans with revised state plans that are no less stringent. A petition for review challenging the 2021 rule has been filed in the D.C. Circuit, but this does not stay the effectiveness of the rule. Mercury and Air Toxic Standards (MATS) . The EPA published the final MATS rule in the Federal Register in 2012. The MATS rule revised the new source performance standards (NSPS) for NO x , SO 2 and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (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. 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 were challenged in the D.C. Circuit but this litigation was placed in abeyance. In August 2020, the EPA sent a draft rule to the Office of Management and Budget for review regarding reconsideration of the “appropriate and necessary” finding as well as standards for coal- and oil-fired EGUs. 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. On August 30, 2021, a federal court in Arizona vacated the Navigable Waters Protection Rule, and on September 3, 2021, the EPA and the Corps announced that they had “halted implementation” of the rule nationwide and that they are interpreting “Waters of the United States” consistent with the pre-2015 regulatory framework. The agencies reaffirmed that they are moving forward on two rulemaking proceedings to formally repeal the Navigable Waters Protection Rule and then to build upon the pre-2015 regulatory framework. Effluent Limitations Guidelines for the Steam Electric Power Generating Industry . On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On October 13, 2020, the EPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. However, on August 3, 2021, the EPA announced it is undertaking a supplemental rulemaking to “strengthen certain discharge limits” applicable to steam electric power plants. As finalized, the revised effluent limitations guidelines could significantly increase costs for many coal-fired steam electric power plants. 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 incrementally returned or security released after satisfactory reclamation is progressively 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. 46 Table of Contents 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 is now under consideration by the Australian Senate. 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 final regulations were promulgated in September 2021. The law requires the 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. The U.S. Congress is considering several measures to address climate issues and greenhouse gas emissions as part of the U.S. budgetary process, including reconciliation legislation that could create financial incentives and penalties as part of a “clean electricity standard” applying to electric generation. 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. 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. NSPS 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. Because NSR review is undertaken both pursuant to applicable regulations and guidance and performed on a “case-by-case” basis, requirements imposed through this permitting process are subject to variation. 47 Table of Contents 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. 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 additional, more specific information with regard to how the goal will be achieved. 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 and/or spending authorities. 48 Table of Contents 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 carbon capture, utilization and storage (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. 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, collateral and margining requirements, 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 September 30, 2021, the Company’s cash balances totaled $587.0 million, including approximately $265 million held by U.S. subsidiaries, $294 million held by Australian subsidiaries, and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. The subsidiaries that conduct the operations of the Wilpinjong Mine held cash of approximately $145 million at September 30, 2021. 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. 49 Table of Contents The Company’s available liquidity declined from $728.7 million as of December 31, 2020 to $615.4 million as of September 30, 2021. Available liquidity was comprised of the following: September 30, 2021 December 31, 2020 (Dollars in millions) Cash and cash equivalents $ 587.0 $ 709.2 Credit facility availability 15.8 0.2 Accounts receivable securitization program availability 12.6 19.3 Total liquidity $ 615.4 $ 728.7 Indebtedness The Company’s total funded indebtedness (Indebtedness) as of September 30, 2021 and December 31, 2020 is presented in the table below. Debt Instrument (defined below, as applicable) September 30, 2021 December 31, 2020 (Dollars in millions) 6.000% Senior Secured Notes due March 2022 (2022 Notes) $ 23.1 $ 459.0 8.500% Senior Secured Notes due December 2024 (Peabody Notes) 128.8 — 10.000% Senior Secured Notes due December 2024 (Co-Issuer Notes) 193.9 — 6.375% Senior Secured Notes due March 2025 (2025 Notes) 462.4 500.0 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) 328.7 388.2 Revolving credit facility — 216.0 Finance lease obligations 30.4 27.3 Less: Debt issuance costs (45.1) (42.7) 1,328.2 1,547.8 Less: Current portion of long-term debt 59.5 44.9 Long-term debt $ 1,268.7 $ 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. 50 Table of Contents 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. 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. 51 Table of Contents 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 $452.2 million at September 30, 2021. 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 September 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. During September 2021, the Company announced that it could offer and sell up to an additional 12.5 million shares, for a total of 25.0 million shares authorized through the at-the-market offering program. Through September 30, 2021, the Company sold approximately 17.1 million shares for net cash proceeds of $177.2 million. Between October 1, 2021 and November 2, 2021, the Company settled sales of an additional 3.2 million shares for net proceeds of $43.4 million. Through September 30, 2021, the Company retired $40.1 million of Peabody Notes, $19.7 million of 2025 Notes and $56.7 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $85.9 million. During the nine months ended September 30, 2021, the Company recorded net gains on early debt extinguishment of $26.9 million related to these retirements. Subsequent to September 30, 2021, the Company retired an additional $5.0 million of its Senior Secured Term Loan through similar open market purchases for an aggregate cost of $3.3 million. Through September 30, 2021, the Company also completed multiple bilateral transactions with holders of the 2022 Notes, the 2025 Notes and the Peabody Notes in which the Company issued an aggregate 6.7 million shares of its common stock in exchange for $37.3 million aggregate principal amount of the 2022 Notes, $17.9 million aggregate principal amount of the 2025 Notes and $5.5 million aggregate principal amount of the Peabody Notes. Between October 1, 2021 and November 2, 2021, the Company issued an additional 1.9 million shares of its common stock in exchange for $31.0 million aggregate principal amount of a combination of Peabody Notes and 2025 Notes. 52 Table of Contents As a result of the Company’s open market purchases of its debt during the three months ended September 30, 2021, on October 22, 2021, the Company announced a Mandatory Repurchase Offer of up to $15.8 million of Peabody Notes, at 73.590% 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 November 22, 2021, unless extended by the Company. Considering the Refinancing Transactions and the subsequent financing transactions described above, the Company expects to incur approximately $190 million of interest expense, including approximately $45 million of non-cash interest expense, during the year ended December 31, 2021. Refer to Note 11. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements for additional information related to the subsequent financing transactions described above. 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 is in discussions 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 September 30, 2021, the Company h a d no outstanding borrowings and $133.6 million of letters of credit issued under the program, which were primarily in support of portions of the Company’s reclamation obligations. The Company was not required to post cash collateral under the Securitization Program at September 30, 2021. 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 nine months ended September 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. Nine Months Ended September 30, 2021 2020 (Dollars in millions) Net cash used in operating activities $ (18.4) $ (32.1) Net cash used in investing activities (119.7) (159.4) Net cash provided by financing activities 15.9 273.9 Net change in cash, cash equivalents and restricted cash (122.2) 82.4 Cash, cash equivalents and restricted cash at beginning of period 709.2 732.2 Cash, cash equivalents and restricted cash at end of period $ 587.0 $ 814.6 Net cash used in operating activities $ (18.4) $ (32.1) Net cash used in investing activities (119.7) (159.4) Free Cash Flow $ (138.1) $ (191.5) 53 Table of Contents Operating Activities. The decrease in net cash used in operating activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by a year-over-year increase in operating cash flow, primarily from the Company’s mining operations ($237.7 million), partially offset by increased cash utilized to satisfy the margin requirements associated with derivative financial instruments ($224.0 million). Investing Activities. The decrease in net cash used in investing activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by lower capital expenditures ($19.9 million) and lower advances to related parties and joint ventures, on a net basis ($13.4 million). Financing Activities. The decrease in net cash provided by financing activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by $360.0 million of revolving loan and securitization borrowings in the prior year, higher repayments of debt principal ($52.6 million) and payments for deferred financing costs ($22.5 million) in the current year, partially offset by $177.2 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 September 30, 2021, such instruments inc lude d $1,462.4 million of surety bonds and $443.2 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 September 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 $ 1,293.4 $ 42.1 $ 79.6 $ 30.9 $ 16.4 $ 1,462.4 Letters of credit outstanding under letter of credit facility 205.7 90.4 7.0 5.0 — 308.1 Letters of credit outstanding under accounts receivable securitization program 110.4 18.9 4.4 — — 133.7 Other letters of credit — 1.4 — — — 1.4 1,609.5 152.8 91.0 35.9 16.4 1,905.6 Less: Letters of credit in support of surety bonds (4) (309.7) (29.8) — (1.2) — (340.7) Less: Cash collateral in support of surety bonds (4) (15.0) — — — — (15.0) Obligations supported, net $ 1,284.8 $ 123.0 $ 91.0 $ 34.7 $ 16.4 $ 1,549.9 (1) Obligations include pension and health care 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 $7.3 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 September 30, 2021, the Company had total asset retirement obligations of $710.2 million which were backed by a combination of surety bonds, bank guarantees and letters of credit. Bonding requirement amounts may differ significantly from the 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 September 30, 2021, the Company identified certain assets with an aggregate carrying value of approximately $1.1 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 as of September 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 September 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