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 “we,” “us,” “our,” “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 our continuing operations. When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms). Cautionary Notice Regarding Forward-Looking Statements This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook” in this Item 2. We use words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements. Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond our control. Factors that could affect our results or an investment in our securities include, but are not limited to: • the combined risks associated with our recent financial results and market conditions, additional collateral demands, and potential Credit Agreement (as defined below) noncompliance raise substantial doubt about whether we will meet our obligations as they become due and our ability to continue as a going concern; • our profitability depends upon the prices we receive for our coal; • if a substantial number of our long-term coal supply agreements terminate, or if the pricing, volumes or other elements of those agreements materially adjust, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts; • the loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues; • our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks; • our operating results could be adversely affected by unfavorable economic and financial market conditions; • our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates; • risks inherent to mining could increase the cost of operating our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us; • if transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal may be diminished; • a decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability; • take-or-pay arrangements within the coal industry could unfavorably affect our profitability; • an inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us could reduce our profitability; • we may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets; • our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel; • we could be negatively affected if we fail to maintain satisfactory labor relations; • we could be adversely affected if we fail to appropriately provide financial assurances for our obligations; • our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal; • our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us; 39 • we may be unable to obtain, renew or maintain permits necessary for our operations, or we may be unable to obtain, renew or maintain such permits without conditions on the manner in which we run our operations, which would reduce our production, cash flows and profitability; • our operations may be affected by sites within or near mining areas deemed to have cultural heritage significance to indigenous peoples, and our mining permits may be rescinded or modified, or our mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites; • our mining operations are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively; • if the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated; • our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable; • we face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability; • our global operations increase our exposure to risks unique to international mining and trading operations; • joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards; • we may undertake further repositioning plans that would require additional charges; • we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if we sustain cyber-attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our employees, our customers or other third-parties; • our business, results of operations, financial condition and prospects could be materially and adversely affected by the recent coronavirus (COVID-19) pandemic and the related effects on public health; • our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect; • concerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have affected and could continue to affect demand for our products or our securities and our ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators; • numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting our future financial results, liquidity and growth prospects; • our financial performance could be adversely affected by our indebtedness; • despite our indebtedness, we may still be able to incur substantially more debt, including secured debt, which could further increase the risks associated with our indebtedness; • the terms of our indenture governing our senior secured notes and the agreements and instruments governing our other indebtedness impose restrictions that may limit our operating and financial flexibility; • the number and quantity of viable financing and insurance alternatives available to us may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around our efforts with respect to environmental and social matters and related governance considerations could harm the perception of our company by certain investors or result in the exclusion of our securities from consideration by those investors; • the price of our securities may be volatile; • our Common Stock is subject to dilution and may be subject to further dilution in the future; • there may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests; • the payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured; • we may not be able to fully utilize our deferred tax assets; • acquisitions and divestitures are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits; 40 • our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt; • diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results; and • other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q. When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our 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 our results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws. Overview We are a leading coal producer. In 2019, we produced and sold 164.7 million and 165.5 million tons of coal, respectively, from continuing operations. Since December 31, 2019, the Millennium Mine in the Seaborne Metallurgical Mining segment and the Wildcat Hills Underground Mine in the Other U.S. Thermal Mining segment shipped their final tons. As a result, we owned interests in 18 active coal mining operations located in the United States (U.S.) and Australia at September 30, 2020. Included in that count is our 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts. We conduct business through four operating segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining and Other U.S. Thermal Mining. Refer to Note 19. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of our Corporate and Other segment. From time to time, we initiate restructuring activities in connection with our repositioning efforts to appropriately align our cost structure or optimize our coal production relative to prevailing market conditions. As further described in the “Results of Operations” section contained within this Item 2, we incurred restructuring charges of $8.1 million and $31.1 million during the three and nine months ended September 30, 2020, respectively, related to workforce reductions made across the organization through the use of both involuntary and voluntary reductions. On October 5, 2020, we announced that we are temporarily idling our Shoal Creek Mine in Alabama over the next several months. While steelmaking fundamentals, particularly in traditional markets, appear to be in the early stages of recovery from the COVID-19 pandemic, customer demand has been and continues to be impacted. These market factors, combined with a currently elevated cost structure at the mine, have led to the decision to temporarily suspend production. We will seek to implement productivity improvements during the idle period. Liquidity and Going Concern As more fully described within “Liquidity and Capital Resources” of this Item 2 and subsequently within Part II, Item 1A. “Risk Factors,” the combined risks associated with our recent financial results, market conditions, additional collateral demands and potential Credit Agreement noncompliance raise substantial doubt about whether we will meet our obligations as they become due within one year from the date of issuance of these unaudited condensed consolidated financial statements and our ability to continue as a going concern. We have experienced negative cash flows from operations during the nine months ended September 30, 2020. Results from continuing operations, net of income taxes and Adjusted EBITDA for the nine months ended September 30, 2020 declined by $1,841.3 million and $487.7 million, respectively, compared to the corresponding prior year period. The Company’s available liquidity declined from $1,275.8 million as of December 31, 2019 to $860.1 million as of September 30, 2020. We are also facing substantial recent collateral demands from our surety bond providers. While we were compliant with the restrictions and covenants under our debt agreements at September 30, 2020, noncompliance with the first lien leverage ratio covenant under our Credit Agreement is probable as of December 31, 2020, if we do not successfully take mitigating actions. Such potential actions include the execution of agreements among Peabody, our surety bond providers, the revolving lenders under our credit agreement, and holders of certain of our senior secured notes with the objective of improving our liquidity risk, providing covenant relief, and extending relevant debt maturities. These actions are more fully described within “Liquidity and Capital Resources” of this Item 2 and subsequently within Part II, Item 1A. “Risk Factors.” 41 Table of Contents Coronavirus (COVID-19) Pandemic On March 11, 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. The pandemic has resulted in governments around the world implementing stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of the COVID-19 pandemic. Coal mining in the U.S. and Australia has been designated as an essential business to support coal-fueled electric power generation and critical steelmaking needs. As part of Peabody’s commitment to the ongoing health and safety of our employees, vendors and communities, we are following advice from government authorities and taking precautions to manage the spread of COVID-19. Peabody operations have implemented rigorous protocols, control and prevention measures, including mandatory temperature and health checks; paid leave for recommended self-isolation periods; enhanced cleaning and sterilization practices; expanded use of personal protective equipment; social distancing; and working remotely when circumstances warrant. While our operations have been designated as essential, each operation will only continue to operate when it is safe and economic to do so. The global impact on economic activity has severely curtailed demand for numerous commodities. Within the global coal industry, supply and demand disruptions have been widespread. The global economy is showing improvement in industrial production, even as the timing of a recovery varies across countries and sectors. However, in the seaborne metallurgical and thermal markets, demand remains below pre-pandemic levels. In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. During the nine months ended September 30, 2020, coal-fueled generation declined 24% compared to the prior year period and now represents 19% of the overall generation mix. Additionally, we have faced disruption to supply chain and distribution channels and adverse effects to our workforce. Coal industry fundamentals, as well as known impacts specific to Peabody, are further addressed in the “Results of Operations” section contained within this Item 2. While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may negatively affect both demand and prices for our products. Given the uncertainties with respect to future COVID-19 developments, including the duration, severity and scope, as well as the necessary government actions to limit the spread, we are unable to estimate the full impact of the pandemic on our business, financial condition, results of operations or cash flows at this time. On March 27, 2020, the President of the United States signed and enacted into law the Coronavirus Aid, Relief and Economic Security Act (the CARES Act), a $2 trillion economic relief bill. The CARES Act contains numerous income tax provisions, including a provision that provides for the acceleration of refunds of previously generated alternative minimum tax credits. Pursuant to the CARES Act, we have received approximately $24 million of accelerated refunds from the Internal Revenue Service and have adjusted our current and deferred tax asset balances accordingly. The CARES Act also contains a provision for deferred payment of 2020 employer payroll taxes after the date of enactment to future years. We will defer a portion of our remaining 2020 employer payroll taxes to subsequent years. United Wambo Joint Venture with Glencore In December 2019, after receiving the requisite regulatory and permitting approvals, we formed an unincorporated joint venture with Glencore plc (Glencore), in which we hold a 50% interest, to combine the existing operations of our Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. We proportionally consolidate the entity based upon our economic interest. Both parties contributed mining tenements upon formation of the joint venture. Construction and development efforts are currently underway to combine operations. During the nine months ended September 30, 2020, the Company contributed and capitalized approximately $45 million towards construction and development. The joint venture agreement specifies that we will continue to fully own and operate the existing Wambo Open-Cut Mine through the date that development of the combined operations is completed, which is currently expected to be during the fourth quarter of 2020. The parties will then contribute mining equipment and other assets, and joint operations will commence. Glencore is responsible for construction and development activities and will manage the mining operations of the joint venture. 42 Table of Contents PRB Colorado Joint Venture with Arch On June 18, 2019, we entered into a definitive implementation agreement with Arch Resources, Inc. (Arch), known as Arch Coal, Inc. prior to May 15, 2020, to establish a joint venture that would have combined the respective Powder River Basin (PRB) and Colorado operations of Peabody and Arch. On February 26, 2020, the U.S. Federal Trade Commission (FTC) sought a preliminary injunction to challenge our proposed joint venture. On September 29, 2020, the United States District Court for the Eastern District of Missouri granted the FTC’s request for a preliminary injunction. Effective September 30, 2020, we terminated our agreement with Arch to establish the joint venture. North Goonyella Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018 and mining operations have been suspended since then. In 2020, we commenced a commercial process and review of strategic alternatives for North Goonyella which is currently ongoing. During 2018 and 2019, we recorded provisions for equipment losses amounting to $149.6 million related to the fire, representing the best estimate of losses to date. Of that amount, $24.7 million was recorded during the nine months ended September 30, 2019. No additional provisions for equipment losses were recorded during the three and nine months ended September 30, 2020. We have also incurred containment and idling costs subsequent to the mine’s suspension which amounted to $3.8 million and $29.3 million during the three months ended September 30, 2020 and 2019, respectively, and $25.2 million and $94.6 million during the nine months ended September 30, 2020 and 2019, respectively. In March 2019, we entered into an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amount of the recovery. Results of Operations Non-GAAP Financial Measures The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to joint ventures as management does not view these items as part of our normal operations. Also included in the following discussion of our results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of our mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2. In our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations. We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP. 43 Table of Contents Three and Nine Months Ended September 30, 2020 Compared to the Three and Nine Months Ended September 30, 2019 Summary Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended September 30, 2020 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the three months ended September 30, 2020 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing we realized during the three months ended September 30, 2020 since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact our realized pricing. High Low Average September 30, 2020 Premium HCC (1) $ 138.10 $ 106.30 $ 114.23 $ 138.10 Premium PCI coal (1) 82.15 65.75 70.58 82.15 Newcastle index thermal coal (1) 59.97 47.99 51.54 57.81 API 5 thermal coal (1) 41.61 35.16 36.91 41.00 PRB 8,800 Btu/Lb coal (2) 11.90 11.55 11.64 11.60 Illinois Basin 11,500 Btu/Lb coal (2) 29.50 27.75 28.53 29.00 (1) Prices expressed per tonne. (2) Prices expressed per ton. Within the global coal industry, supply and demand disruptions have been widespread as the COVID-19 pandemic has forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread. The global coal industry data for the nine months ended September 30, 2020 presented herein is not indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration, the significant decline in prices from pre-pandemic levels for our products and continued weak demand for our products. With respect to seaborne metallurgical coal, global steel production decreased approximately 3% through the nine months ended September 30, 2020 compared to the prior year period, as the COVID-19 pandemic has significantly impacted steel demand. Excluding China, steel production was down approximately 13% due to COVID-19, while Chinese steel production increased approximately 6% during this same period. While global steel production has remained lower year-over-year, there has been consistent improvement in steel production since July 2020 as COVID-19 related lockdown restrictions have eased in key countries. In August, China set a new monthly steel production record as the country continues to stimulate the economy through construction and infrastructure projects. Improved steel demand has caused steelmakers, including Peabody customers, to restart capacity and increase output, resulting in improvements in seaborne metallurgical coal demand. However, India and Japan, in particular, remain challenged. Industrial activity in India is recovering, but is threatened by the continued worsening spread of COVID-19. The recovery in Europe remains challenged amid automotive sector weakness and increasing COVID-19 cases. In addition, China’s metallurgical coal imports have been limited recently by intensified import restrictions, which are likely to remain a key factor for the remainder of 2020. 44 Table of Contents Within the seaborne thermal coal market, demand remains below pre-pandemic levels in many key countries, and headwinds such as COVID-19, China import restrictions and competition from alternative fuel sources, including natural gas persist. China thermal imports were down 9 million tonnes through the nine months ended September 30, 2020. India has seen domestic power demand recover, but thermal imports are down by approximately 24 million tonnes through the nine months ended September 30, 2020 compared to the prior year and are likely to remain under pressure given existing stockpiles and domestic production growth. In the United States, overall electricity demand has been negatively impacted year-over-year due to COVID-19 induced economic shutdowns during the nine months ended September 30, 2020. The reduction in thermal coal demand during that period has outpaced the reduction in overall electricity demand as continued coal plant retirements, growth in natural gas and renewable generation and weak natural gas prices continue to negatively impact coal’s share of electricity generation. Lower total electricity demand driven by COVID-19 related curtailments has resulted in coal’s share of generation declining to approximately 19% for the nine months ended September 30, 2020, while natural gas and renewables continue to gain. Through the nine months ended September 30, 2020 utility consumption of PRB coal fell approximately 25% compared to the prior year period. Our revenues for the three and nine months ended September 30, 2020 decreased compared to the same periods in 2019 ($435.4 million and $1,362.1 million, respectively) primarily due to lower sales volumes which were affected by the COVID-19 pandemic and lower realized prices. Results from continuing operations, net of income taxes for the three months ended September 30, 2020 increased compared to the same period in the prior year ($9.5 million) as the result of lower operating costs and expenses due largely to the sales volume decline as well as production efficiencies and other cost improvements ($354.6 million) and lower depreciation, depletion and amortization ($69.3 million). These favorable variances were offset by the unfavorable revenue variance described above. Results from continuing operations, net of income taxes for the nine months ended September 30, 2020 decreased compared to the same period in the prior year ($1,841.3 million) primarily due to higher asset impairment charges recorded in the current year ($1,398.1 million), the unfavorable revenue variance described above and a prior year insurance recovery related to the events at our North Goonyella Mine ($125.0 million). These unfavorable variances were partially offset by lower operating costs and expenses as described above ($824.8 million) and lower depreciation, depletion and amortization ($212.9 million). Adjusted EBITDA for the three and nine months ended September 30, 2020 reflected a year-over-year decrease of $63.8 million and $487.7 million, respectively. As of September 30, 2020, our available liquidity was approximately $860 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting our available liquidity. Tons Sold The following table presents tons sold by operating segment: Three Months Ended Decrease Nine Months Ended (Decrease) Increase September 30, to Volumes September 30, to Volumes 2020 2019 Tons % 2020 2019 Tons % (Tons in millions) (Tons in millions) Seaborne Thermal Mining 4.6 4.9 (0.3) (6) % 13.8 14.1 (0.3) (2) % Seaborne Metallurgical Mining 1.1 1.8 (0.7) (39) % 4.2 6.2 (2.0) (32) % Powder River Basin Mining 23.6 30.2 (6.6) (22) % 65.0 80.5 (15.5) (19) % Other U.S. Thermal Mining 4.8 7.2 (2.4) (33) % 13.5 22.3 (8.8) (39) % Total tons sold from mining segments 34.1 44.1 (10.0) (23) % 96.5 123.1 (26.6) (22) % Corporate and Other 0.6 0.7 (0.1) (14) % 2.1 1.6 0.5 31 % Total tons sold 34.7 44.8 (10.1) (23) % 98.6 124.7 (26.1) (21) % 45 Table of Contents Supplemental Financial Data The following table presents supplemental financial data by operating segment: Three Months Ended (Decrease) Nine Months Ended (Decrease) September 30, Increase September 30, Increase 2020 2019 $ % 2020 2019 $ % Revenues per Ton - Mining Operations (1) Seaborne Thermal $ 35.28 $ 51.06 $ (15.78) (31) % $ 38.14 $ 51.14 $ (13.00) (25) % Seaborne Metallurgical 71.88 120.94 (49.06) (41) % 87.16 134.80 (47.64) (35) % Powder River Basin 11.26 11.02 0.24 2 % 11.35 11.22 0.13 1 % Other U.S. Thermal 37.20 45.45 (8.25) (18) % 38.67 43.52 (4.85) (11) % Costs per Ton - Mining Operations (1)(2) Seaborne Thermal $ 27.59 $ 35.33 $ (7.74) (22) % $ 29.58 $ 33.69 $ (4.11) (12) % Seaborne Metallurgical (3) 96.87 130.01 (33.14) (25) % 110.20 114.22 (4.02) (4) % Powder River Basin 7.93 8.69 (0.76) (9) % 9.15 9.39 (0.24) (3) % Other U.S. Thermal 26.52 34.00 (7.48) (22) % 29.60 32.70 (3.10) (9) % Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) Seaborne Thermal $ 7.69 $ 15.73 $ (8.04) (51) % $ 8.56 $ 17.45 $ (8.89) (51) % Seaborne Metallurgical (3) (24.99) (9.07) (15.92) (176) % (23.04) 20.58 (43.62) (212) % Powder River Basin 3.33 2.33 1.00 43 % 2.20 1.83 0.37 20 % Other U.S. Thermal 10.68 11.45 (0.77) (7) % 9.07 10.82 (1.75) (16) % (1) This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. (2) Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. (3) Costs incurred at the North Goonyella Mine from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred at the North Goonyella Mine during the three and nine months ended September 30, 2019 remain within the Seaborne Metallurgical Mining segment and resulted in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton of $16.38 and $9.84, respectively. Revenues The following table presents revenues by reporting segment: Three Months Ended (Decrease) Increase Nine Months Ended Decrease September 30, to Revenues September 30, to Revenues 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 163.0 $ 249.5 $ (86.5) (35) % $ 526.1 $ 720.7 $ (194.6) (27) % Seaborne Metallurgical Mining 78.8 216.3 (137.5) (64) % 363.6 831.7 (468.1) (56) % Powder River Basin Mining 264.8 333.6 (68.8) (21) % 737.2 903.5 (166.3) (18) % Other U.S. Thermal Mining 179.8 326.4 (146.6) (45) % 524.1 970.8 (446.7) (46) % Corporate and Other (15.4) (19.4) 4.0 21 % (7.1) 79.3 (86.4) (109) % Revenues $ 671.0 $ 1,106.4 $ (435.4) (39) % $ 2,143.9 $ 3,506.0 $ (1,362.1) (39) % Seaborne Thermal Mining. Segment revenues decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year due to unfavorable realized coal pricing (three months, $69.7 million; nine months, $164.7 million) and unfavorable volume and mix variances (three months, $16.8 million; nine months, $29.9 million). 46 Table of Contents Seaborne Metallurgical Mining. Segment revenues decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year due to unfavorable volume and mix variances (three months, $87.2 million; nine months, $294.0 million) and unfavorable realized coal pricing (three months, $50.3 million; nine months, $174.1 million). The unfavorable volume variances primarily resulted from demand-based volume decreases across our mines. Powder River Basin Mining. Segment revenues decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year primarily due to demand-based volume decreases (three months, $79.8 million; nine months, $184.1 million), partially offset by favorable realized coal pricing (three months, $11.0 million; nine months, $17.8 million). Other U.S. Thermal Mining. Segment revenues decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year primarily due to volume decreases (three months, $127.6 million; nine months, $418.4 million) which were driven by the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Wildcat Hills Underground Mine during the second quarter of 2020 and unfavorable realized pricing (three months, $19.0 million; nine months, $28.3 million). Corporate and Other. Segment revenues increased during the three months ended September 30, 2020 compared to the same period in the prior year primarily due to higher results on economic hedge activities. Segment revenues decreased during the nine months ended September 30, 2020 compared to the same period in the prior year primarily due to lower results on economic hedge activities. Adjusted EBITDA The following table presents Adjusted EBITDA for each of our reporting segments: Three Months Ended (Decrease) Increase Nine Months Ended Decrease September 30, to Segment Adjusted EBITDA September 30, to Segment Adjusted EBITDA 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ 35.3 $ 76.8 $ (41.5) (54) % $ 118.1 $ 245.9 $ (127.8) (52) % Seaborne Metallurgical Mining (27.3) (16.2) (11.1) (69) % (96.1) 127.0 (223.1) (176) % Powder River Basin Mining 78.3 70.7 7.6 11 % 143.0 147.3 (4.3) (3) % Other U.S. Thermal Mining 51.6 82.3 (30.7) (37) % 123.0 241.3 (118.3) (49) % Corporate and Other (42.5) (54.4) 11.9 22 % (132.4) (118.2) (14.2) (12) % Adjusted EBITDA (1) $ 95.4 $ 159.2 $ (63.8) (40) % $ 155.6 $ 643.3 $ (487.7) (76) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2020 compared to the same period in the prior year as a result of lower realized net coal pricing ($64.0 million) and unfavorable volume variances ($8.3 million). The decrease was partially offset by favorable mine sequencing impacts and cost improvements at our thermal surface mines ($31.4 million). Segment Adjusted EBITDA decreased during the nine months ended September 30, 2020 compared to the same period in the prior year as a result of lower realized net coal pricing ($151.4 million), a temporary shutdown at our Wambo Underground Mine ($18.5 million) and unfavorable volume variances ($17.9 million). The decrease was partially offset by favorable mine sequencing impacts and lower costs for materials, services and repairs at our thermal surface mines ($36.0 million), favorable foreign currency impacts ($10.5 million) and lower pricing for fuel ($9.5 million). 47 Table of Contents Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year due to lower realized net coal pricing (three months, $47.0 million; nine months, $162.7 million), unfavorable volume variances (three months, $24.3 million; nine months, $88.7 million), higher costs associated with the conveyor upgrade at our Shoal Creek Mine (three months, $18.7 million; nine months, $47.8 million) and non-cash charges to record certain mines’ coal inventories to their net realizable values (nine months, $20.7 million). These negative variances were partially offset by the exclusion of the current year containment and holding costs for our North Goonyella Mine (three months, $29.3 million; nine months, $60.7 million), lower costs for materials, services and repairs at our Coppabella and Moorvale Mines (three months, $23.5 million; nine months, $12.8 million), favorable costs at our Metropolitan Mine due to initiatives implemented earlier in the year (three months, $19.1 million) and favorable foreign currency impacts (nine months, $19.2 million). Powder River Basin Mining. Segment Adjusted EBITDA increased during the three months ended September 30, 2020 compared to the same period in the prior year due to lower costs for materials, services, repairs and labor ($13.1 million), higher realized net coal pricing ($6.5 million), lower pricing for fuel and explosives ($4.6 million) and reduced commodity usage ($3.0 million). The increase was partially offset by the impact of lower volumes ($17.4 million). Segment Adjusted EBITDA decreased during the nine months ended September 30, 2020 compared to the same period in the prior year as the result of unfavorable mine sequencing impacts ($43.4 million) and the impact of lower volumes ($33.5 million), offset by lower costs for materials, services, repairs and labor ($44.4 million), lower pricing for fuel and explosives ($17.5 million) and reduced commodity usage ($5.2 million). Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year due to the impact of lower volume (three months, $42.6 million; nine months, $136.7 million) which was primarily driven by the closure of the Kayenta Mine during the third quarter of 2019, lower realized net coal pricing (three months, $17.4 million; nine months, $28.3 million) and unfavorable mine sequencing impacts (nine months, $12.8 million); partially offset by lower costs for materials, services, repairs and labor (three months, $19.0 million; nine months, $39.8 million) and lower pricing for fuel and explosives (three months, $3.8 million; nine months, $13.1 million). Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: Three Months Ended Increase (Decrease) Nine Months Ended (Decrease) Increase September 30, to Adjusted EBITDA September 30, to Adjusted EBITDA 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) Middlemount (1) $ (11.1) $ (18.8) $ 7.7 41 % $ (27.2) $ (4.9) $ (22.3) (455) % Resource management activities (2) 1.0 2.3 (1.3) (57) % 9.8 6.0 3.8 63 % Selling and administrative expenses (27.2) (32.2) 5.0 16 % (77.3) (107.8) 30.5 28 % Other items, net (3)(4) (5.2) (5.7) 0.5 9 % (37.7) (11.5) (26.2) (228) % Corporate and Other Adjusted EBITDA $ (42.5) $ (54.4) $ 11.9 22 % $ (132.4) $ (118.2) $ (14.2) (12) % (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 $8.6 million and $3.1 million during the three months ended September 30, 2020 and 2019, respectively, and $21.8 million and $20.1 million during the nine months ended September 30, 2020 and 2019, respectively. (2) Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. (3) Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and expenses related to our other commercial activities. (4) North Goonyella costs incurred from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred prior to January 1, 2020 remain within the Seaborne Metallurgical Mining segment. The increase in Corporate and Other Adjusted EBITDA during the three months ended September 30, 2020 compared to the same period in the prior year was primarily driven by a favorable variance in Middlemount’s results due to increased sales volumes. The increase was also driven by lower selling and administrative expenses due to lower personnel costs and reduced expense associated with our share-based incentive plans. 48 Table of Contents The decrease in Corporate and Other Adjusted EBITDA during the nine months ended September 30, 2020 compared to the same period in the prior year was primarily driven by current year containment and holding costs for our North Goonyella Mine ($25.2 million) and an unfavorable variance in Middlemount’s results due to the continuing impacts of a significant change to the mine plan following a highwall failure in mid-2019. These unfavorable variances were partially offset by lower selling and administrative expenses driven by lower personnel costs and reduced expense associated with our share-based incentive plans. (Loss) Income From Continuing Operations, Net of Income Taxes The following table presents (loss) income from continuing operations, net of income taxes: Three Months Ended (Decrease) Increase Nine Months Ended (Decrease) Increase September 30, to Income September 30, to Income 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) Adjusted EBITDA (1) $ 95.4 $ 159.2 $ (63.8) (40) % $ 155.6 $ 643.3 $ (487.7) (76) % Depreciation, depletion and amortization (72.2) (141.5) 69.3 49 % (266.5) (479.4) 212.9 44 % Asset retirement obligation expenses (14.3) (15.5) 1.2 8 % (46.0) (44.6) (1.4) (3) % Restructuring charges (8.1) (0.7) (7.4) (1,057) % (31.1) (1.3) (29.8) (2,292) % Transaction costs related to joint ventures (6.0) (8.2) 2.2 27 % (23.1) (9.8) (13.3) (136) % Asset impairment — (20.0) 20.0 100 % (1,418.1) (20.0) (1,398.1) (6,991) % Provision for North Goonyella equipment loss — — — n.m. — (24.7) 24.7 100 % North Goonyella insurance recovery - equipment — — — n.m. — 91.1 (91.1) (100) % Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 0.5 — 0.5 n.m. 1.6 (0.3) 1.9 633 % Interest expense (34.9) (35.4) 0.5 1 % (102.3) (107.2) 4.9 5 % Interest income 1.6 7.0 (5.4) (77) % 7.1 22.5 (15.4) (68) % Net mark-to-market adjustment on actuarially determined liabilities (13.0) — (13.0) n.m. (13.0) — (13.0) n.m. Unrealized (losses) gains on economic hedges (16.1) (18.0) 1.9 11 % (11.3) 44.2 (55.5) (126) % Unrealized gains on non-coal trading derivative contracts 0.7 0.3 0.4 133 % 3.6 0.2 3.4 1,700 % Take-or-pay contract-based intangible recognition 1.5 2.7 (1.2) (44) % 6.8 13.9 (7.1) (51) % Income tax benefit (provision) 0.1 (4.2) 4.3 102 % (2.7) (26.0) 23.3 90 % (Loss) income from continuing operations, net of income taxes $ (64.8) $ (74.3) $ 9.5 13 % $ (1,739.4) $ 101.9 $ (1,841.3) (1,807) % (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. 49 Table of Contents Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment: Three Months Ended Increase (Decrease) Nine Months Ended Increase (Decrease) September 30, to Income September 30, to Income 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal Mining $ (20.2) $ (22.4) $ 2.2 10 % $ (62.9) $ (67.6) $ 4.7 7 % Seaborne Metallurgical Mining (20.0) (28.7) 8.7 30 % (65.3) (99.9) 34.6 35 % Powder River Basin Mining (10.9) (38.3) 27.4 72 % (74.4) (110.9) 36.5 33 % Other U.S. Thermal Mining (16.9) (50.1) 33.2 66 % (53.9) (194.6) 140.7 72 % Corporate and Other (4.2) (2.0) (2.2) (110) % (10.0) (6.4) (3.6) (56) % Total $ (72.2) $ (141.5) $ 69.3 49 % $ (266.5) $ (479.4) $ 212.9 44 % Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments: Three Months Ended Nine Months Ended September 30, September 30, 2020 2019 2020 2019 Seaborne Thermal Mining $ 1.78 $ 1.78 $ 1.92 $ 1.85 Seaborne Metallurgical Mining 1.83 3.97 2.24 3.29 Powder River Basin Mining 0.23 0.81 0.59 0.81 Other U.S. Thermal Mining 1.11 1.15 1.05 1.40 Depreciation, depletion and amortization expense decreased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year primarily due to the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Millennium and Wildcat Hills Underground Mines during the second quarter of 2020 (three months, $26.6 million; nine months, $121.6 million), the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 (three and nine months, $26.3 million), decreased depletion driven by lower sales volumes (three months, $6.4 million; nine months, $19.7 million) and lower amortization of the fair value of certain U.S. coal supply agreements (three months, $5.5 million; nine months, $16.9 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, 2020 compared to the same periods in the prior year reflects the volume and mix variances which impacted our revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the three and nine months ended September 30, 2020 compared to the same periods in the prior year reflects the asset impairment recorded during the second quarter of 2020. Restructuring Charges. Restructuring charges increased during the three and nine months ended September 30, 2020 compared to the same periods in the prior year as the result of workforce reductions made across the organization through the use of involuntary and voluntary reductions, as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements. Transaction Costs Related to Joint Ventures. The charges recorded during the current and prior year periods related to the proposed PRB Colorado joint venture with Arch as further described in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements. Asset Impairment. During the nine months ended September 30, 2020, we recognized $1,418.1 million in aggregate asset impairment charges related to the fair value of our North Antelope Rochelle Mine as discussed in Note 9. “Property, Plant, Equipment and Mine Development” to the accompanying unaudited condensed consolidated financial statements. During the three and nine months ended September 30, 2019, we recorded asset impairment charges related to the estimated fair value of our Wildcat Hills Underground Mine, which shipped its final tons during the second quarter of 2020. Provision for North Goonyella Equipment Loss. A provision for expected equipment losses related to the events at our North Goonyella Mine was recorded during the prior year as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements. 50 Table of Contents North Goonyella Insurance Recovery - Equipment. During the nine months ended September 30, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the nine months ended September 30, 2019. Interest Income. The decrease in interest income during the three and nine months ended September 30, 2020 compared to the same periods in the prior year was driven by the conclusion of a contract during the fourth quarter of 2019 which contained an embedded financing element and by lower cash balances. 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 to one of our postretirement health care benefit plans which triggered a remeasurement event. For additional details, refer to Note 13. “Pension and Postretirement Benefit Costs” to the accompanying unaudited condensed consolidated financial statements. Unrealized (Losses) Gains on Economic Hedges. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Take-or-Pay Contract-Based Intangible Recognition. During the three and nine months ended September 30, 2020 and 2019, we ratably recognized contract-based intangible liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 8. “Intangible Contract Assets and Liabilities” to the accompanying unaudited condensed consolidated financial statements. Income Tax Benefit (Provision) . The decrease in the income tax provision for the three and nine months ended September 30, 2020 compared to the same periods in the prior year was primarily due to changes in forecasted taxable income, partially offset by an increase in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 11. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information. Net (Loss) Income Attributable to Common Stockholders The following table presents net (loss) income attributable to common stockholders: Three Months Ended Increase (Decrease) Nine Months Ended (Decrease) Increase September 30, to Income September 30, to Income 2020 2019 $ % 2020 2019 $ % (Dollars in millions) (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (64.8) $ (74.3) $ 9.5 13 % $ (1,739.4) $ 101.9 $ (1,841.3) (1,807) % Loss from discontinued operations, net of income taxes (2.3) (3.8) 1.5 39 % (6.8) (10.6) 3.8 36 % Net (loss) income (67.1) (78.1) 11.0 14 % (1,746.2) 91.3 (1,837.5) (2,013) % Less: Net income (loss) attributable to noncontrolling interests 0.1 4.7 (4.6) (98) % (5.1) 12.8 (17.9) (140) % Net (loss) income attributable to common stockholders $ (67.2) $ (82.8) $ 15.6 19 % $ (1,741.1) $ 78.5 $ (1,819.6) (2,318) % Net Income (Loss) Attributable to Noncontrolling Interests . The decrease in net results attributable to noncontrolling interests during the three and nine months ended September 30, 2020 compared to the prior year periods was primarily due to lower results of our majority-owned mines in which there is an outside non-controlling interest. 51 Table of Contents Diluted Earnings per Share (EPS) The following table presents diluted EPS: Three Months Ended Increase Nine Months Ended (Decrease) Increase September 30, to EPS September 30, to EPS 2020 2019 $ % 2020 2019 $ % Diluted EPS attributable to common stockholders: (Loss) income from continuing operations $ (0.66) $ (0.77) $ 0.11 14 % $ (17.76) $ 0.83 $ (18.59) (2,240) % Loss from discontinued operations (0.03) (0.04) 0.01 25 % (0.07) (0.10) 0.03 30 % Net (loss) income attributable to common stockholders $ (0.69) $ (0.81) $ 0.12 15 % $ (17.83) $ 0.73 $ (18.56) (2,542) % Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 97.9 million and 102.2 million for the three months ended September 30, 2020 and 2019, respectively, and 97.6 million and 107.4 million for the nine months ended September 30, 2020 and 2019, respectively. Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance, as displayed in the reconciliations below. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to joint ventures as management does not view these items as part of our normal operations. Three Months Ended Nine Months Ended September 30, September 30, 2020 2019 2020 2019 (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (64.8) $ (74.3) $ (1,739.4) $ 101.9 Depreciation, depletion and amortization 72.2 141.5 266.5 479.4 Asset retirement obligation expenses 14.3 15.5 46.0 44.6 Restructuring charges 8.1 0.7 31.1 1.3 Transaction costs related to joint ventures 6.0 8.2 23.1 9.8 Asset impairment — 20.0 1,418.1 20.0 Provision for North Goonyella equipment loss — — — 24.7 North Goonyella insurance recovery - equipment — — — (91.1) Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates (0.5) — (1.6) 0.3 Interest expense 34.9 35.4 102.3 107.2 Interest income (1.6) (7.0) (7.1) (22.5) Net mark-to-market adjustment on actuarially determined liabilities 13.0 — 13.0 — Unrealized losses (gains) on economic hedges 16.1 18.0 11.3 (44.2) Unrealized gains on non-coal trading derivative contracts (0.7) (0.3) (3.6) (0.2) Take-or-pay contract-based intangible recognition (1.5) (2.7) (6.8) (13.9) Income tax (benefit) provision (0.1) 4.2 2.7 26.0 Total Adjusted EBITDA $ 95.4 $ 159.2 $ 155.6 $ 643.3 52 Table of Contents 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 Nine Months Ended September 30, September 30, 2020 2019 2020 2019 (Dollars in millions) Operating costs and expenses $ 550.9 $ 905.5 $ 1,886.7 $ 2,711.5 Unrealized gains on non-coal trading derivative contracts 0.7 0.3 3.6 0.2 Take-or-pay contract-based intangible recognition 1.5 2.7 6.8 13.9 North Goonyella insurance recovery - cost recovery and business interruption — — — (33.9) Net periodic benefit costs, excluding service cost 2.8 4.9 8.3 14.6 Total Reporting Segment Costs $ 555.9 $ 913.4 $ 1,905.4 $ 2,706.3 The following table presents Reporting Segment Costs by reporting segment: Three Months Ended Nine Months Ended September 30, September 30, 2020 2019 2020 2019 (Dollars in millions) Seaborne Thermal Mining $ 127.7 $ 172.7 $ 408.0 $ 474.8 Seaborne Metallurgical Mining 106.1 232.5 459.7 704.7 Powder River Basin Mining 186.5 262.9 594.2 756.2 Other U.S. Thermal Mining 128.2 244.1 401.1 729.5 Corporate and Other 7.4 1.2 42.4 41.1 Total Reporting Segment Costs $ 555.9 $ 913.4 $ 1,905.4 $ 2,706.3 The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment: 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 53 Table of Contents Three Months Ended September 30, 2019 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 4.9 1.8 30.2 7.2 Revenues $ 249.5 $ 216.3 $ 333.6 $ 326.4 Reporting Segment Costs 172.7 232.5 262.9 244.1 Adjusted EBITDA 76.8 (16.2) 70.7 82.3 Revenues per Ton $ 51.06 $ 120.94 $ 11.02 $ 45.45 Costs per Ton 35.33 130.01 8.69 34.00 Adjusted EBITDA Margin per Ton 15.73 (9.07) 2.33 11.45 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 Nine Months Ended September 30, 2019 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining (Amounts in millions, except per ton data) Tons sold 14.1 6.2 80.5 22.3 Revenues $ 720.7 $ 831.7 $ 903.5 $ 970.8 Reporting Segment Costs 474.8 704.7 756.2 729.5 Adjusted EBITDA 245.9 127.0 147.3 241.3 Revenues per Ton $ 51.14 $ 134.80 $ 11.22 $ 43.52 Costs per Ton 33.69 114.22 9.39 32.70 Adjusted EBITDA Margin per Ton 17.45 20.58 1.83 10.82 54 Table of Contents Free Cash Flow is defined as net cash (used in) provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP. Nine Months Ended September 30, 2020 2019 (Dollars in millions) Net cash (used in) provided by operating activities $ (32.1) $ 552.6 Net cash used in investing activities (159.4) (147.6) Add back: Amount attributable to acquisition of Shoal Creek Mine — 2.4 Free Cash Flow $ (191.5) $ 407.4 Outlook As part of its normal planning and forecasting process, Peabody utilizes a broad approach to develop macroeconomic assumptions for key variables, including country-level gross domestic product, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections for key demand centers for coal, electricity generation and steel. Specific to the U.S., the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates. Our estimates involve risks and uncertainties and are subject to change based on various factors as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Item 2. Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook. Peabody is continuing to monitor the rapidly evolving COVID-19 pandemic and any impacts related to both our near-term and long-term outlook. Near-Term Outlook While timing of recovery varies across countries and sectors, the global economy is showing improvement in industrial production. However, seaborne coal pricing remains muted and below pre-pandemic levels and rising COVID-19 cases worldwide continue to pose a threat to commodity pricing. Steel industry fundamentals are improving in most regions relative to COVID-driven lows earlier in the year, though seaborne metallurgical coal demand has not yet recovered to pre-pandemic levels. While China is leading the steel production recovery, its metallurgical coal demand has been muted due to ongoing import restrictions. In addition, year-to-date through September 30, 2020, India’s metallurgical imports fell 8 million tonnes compared to the prior year. Within seaborne thermal, weak demand continues to pressure prices. During the nine months ended September 30, 2020, India imports have declined 24 million tonnes due to existing stockpiles and higher domestic production, and China imports are down 9 million tonnes from the corresponding prior year period. Countries comprising the Association of Southeast Asian Nations (ASEAN) are the only major importing regions showing sizable year-over-year growth, with imports up 9 million tonnes year-to-date through September 30, 2020. In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. During the nine months ended September 30, 2020, coal-fueled generation declined 24% compared to the prior year period and now represents 19% of the overall generation mix. However, recent increases in natural gas pricing may benefit near-term coal-fueled generation, with relevant forward prices averaging above $3.00 per mmBtu for the remainder of the year and into 2021. Long-Term Outlook Given widespread industry changes, in part due to the prolonged COVID-19 pandemic, we have updated our long-term outlook. Current projections indicate a slow seaborne market recovery over the next 12 months. Future demand will be impacted by economic conditions and public policy related to the COVID-19 pandemic in key demand centers. Further, we believe coal demand and use will be adversely impacted by the policy decisions of various governments, regulatory bodies, financial institutions and others with respect to concerns over the environmental and social impacts of coal combustion. 55 Table of Contents Seaborne Fundamentals . Peabody projects global seaborne metallurgical demand to show consistent, albeit modest, growth over the next several years. During this time, India is expected to account for the vast majority of overall demand growth amid significant steel capacity additions and lack of domestic reserves. ASEAN countries are also projected to be a notable contributor to growth as demand in Japan and Korea remains largely stable. Australia will continue to account for more than 50% of seaborne supply. For seaborne thermal, Peabody expects ASEAN countries and India to be drivers for seaborne coal demand growth due to increased electrification and economic gains. This growth is anticipated to more than offset declines from developed economies, including the U.S. and Europe. Seaborne thermal coal will continue to be sourced primarily from seaborne exporters Indonesia and Australia, along with Russia, Colombia, South Africa and the U.S., among others. U.S. Fundamentals. U.S. thermal coal demand has been dramatically reduced year-to-date, accelerating the secular demand decline already underway. Future demand will be highly dependent on natural gas prices, growth in renewable generation and other competing fuels, and policy and regulations, among other factors. Regulatory Update Other than as described in the following section, there were no significant changes to our regulatory matters subsequent to December 31, 2019. Information regarding our regulatory matters is outlined in Part I, Item 1. “Business” in our Annual Report on Form 10-K for the year ended December 31, 2019. Regulatory Matters - U.S. Temporary Enforcement Policy . On March 26, 2020, the United States Environmental Protection Agency (EPA) announced a temporary policy regarding EPA enforcement of environmental legal obligations as a result of the COVID-19 pandemic. (COVID-19 Implications for EPA’s Enforcement and Compliance Assurance Program). Under the temporary policy, the EPA will exercise the enforcement discretion for certain noncompliance events that occur during the period of time that the temporary policy is in effect and that result from the COVID-19 pandemic. The EPA’s temporary policy does not provide leniency for intentional criminal violations of law and imposes conditions on any violation that may result in “acute risk or an imminent threat to human health or the environment.” The policy also does not apply to activities that are carried out under Superfund and Resource Conservation and Recovery Act (RCRA) Corrective Action enforcement instruments. The EPA's temporary policy became retroactively effective on March 13, 2020 and remained in effect until August 31, 2020. (COVID-19 Implications for EPA’s Enforcement and Compliance Assurance Program: Addendum on Termination, June 29, 2020). Clean Air Act (CAA) . The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO 2 ). In recent years, the EPA has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO 2 . It is possible that these modifications, as well as future modifications to NAAQS, could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle and/or engine emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS. In 2009, the EPA adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent in 2012. In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 parts per billion (ppb). (80 Fed. Reg. 65,292 (Oct. 25, 2015)). The primary ozone standard was upheld by the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in Murray Energy v. EPA , (D.C. Cir. 2019), Slip Op. 15-1385. The court, however, remanded the secondary ozone NAAQS standard to the EPA and vacated a “grandfathering” provision concerning the use of the prior ozone NAAQS in certain permitting actions. The Clean Air Act requires EPA to review NAAQS every five years to determine whether revision to current standards are appropriate. 42 U.S.C. §7409(d). As part of this recurring review process, the EPA has proposed to retain the ozone standards promulgated in 2015, including current secondary standards. 85 Fed. Reg. 49,830 (Aug. 14, 2020). 56 Table of Contents The EPA is additionally considering whether any revisions are necessary for the 2012 PM NAAQS. The EPA has proposed to retain the current PM standards (85 Fed. Reg. 24,094 (Apr. 30, 2020)). The EPA may take final action concerning both proposed rules by the end of 2020 (See Regulatory Identification Numbers 2060 AU40, 2060-AS50). More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxide and SO 2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQS for SO 2 of 75 ppb averaged over an hour. The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of SO 2 , nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review. In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed. At present, however, the EPA does not directly regulate such emissions. EPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired EGUs under Section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline). Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the D.C. Circuit. The petitions reflected challenges by 27 states and governmental entities, as well as by utilities, industry groups, trade associations, coal companies and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states also joined) (D.C. Cir. No. 15-1363). On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states. The motion was granted on January 11, 2016. Numerous states and other entities also intervened in support of the EPA. On February 9, 2016, the U.S. Supreme Court granted a motion to stay implementation of the CPP until the legal challenges were resolved. Thereafter, oral arguments in the case were heard in the D.C. Circuit sitting en banc. On April 28, 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the agency reconsidered the rule. In October 2017, the EPA proposed to repeal the CPP (82 Fed. Reg. 48,035 (Oct. 16, 2017)). In August 2018, the EPA issued a proposed rule to replace the CPP with the Affordable Clean Energy (ACE) Rule. (83 Fed. Reg. 44,746 (August 31, 2018)). On June 19, 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. (Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations, 84 Fed. Reg. 32,520 (July 8, 2019)). The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction. The EPA’s final rule also revises the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans. Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including Peabody, filed a motion to dismiss, which the court granted in September 2019. Numerous petitions for review challenging the ACE Rule were filed in the D.C. Circuit and consolidated in American Lung Association. v. EPA (No. 19-1140 (D.C. Cir.)). This litigation has been fully briefed and oral argument before a 3-judge panel of the D.C. Circuit was held on October 8, 2020. The oral argument was organized around four issue areas concerning EPA’s repeal of the CPP, EPA’s authority to regulate power plants under the Clean Air Act, whether the ACE rule properly interpreted and applied the Clean Air Act and the treatment of biomass in the ACE Rule. A decision by the panel is pending. 57 Table of Contents Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule . On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. Following litigation in the D.C. Circuit and U.S. Supreme Court, the first phase of the nitrogen oxide and SO 2 emissions reductions required by CSAPR commenced in January 2015; further reductions of both pollutants in the second phase of CSAPR became effective in January 2017. The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO 2 (82 Fed. Reg. 45,481 (Sept. 29, 2017)). On October 26, 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 ozone NAAQS. This rule imposed reductions in nitrogen oxides emissions beginning in 2017 in 22 states subject to CSAPR. Several states and utilities, as well as agricultural and industry groups, filed petitions for review of the CSAPR Update Rule in the D.C. Circuit. Wisconsin v. EPA , No. 16-1406. On September 13, 2019, the D.C. Circuit held that the CSAPR Update Rule did not comply with provisions of the Clean Air Act requiring upwind states to address air pollution which significantly interferes with the ability of a downwind state or states to attain NAAQS by relevant compliance dates. The court thus remanded the CSAPR Update Rule to the EPA in order for the Agency to address the court’s decision. In 2018, the EPA issued another determination that the existing CSAPR Update Rule fully addressed the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 NAAQS for ground-level ozone. (83 Fed. Reg. 65,878 (Dec. 21, 2018)).This determination was also challenged in the D.C. Circuit (No. 19-1019). On October 1, 2019, the D.C. Circuit issued a judgment vacating this rule on the basis of the court’s decision in Wisconsin v. EPA . Additional litigation concerning the interstate transport of air pollution and EPA’s response under the Clean Act continues. In Maryland v. EPA (No. 18-1285), the D.C. Circuit upheld EPA determinations that upwind states had not met their burden in seeking relief from transported air pollution under the same Clean Air Act provisions at issue in Wisconsin. In New York v. EPA, No. 19-1231 (D.C. Cir., July 14, 2020), the D.C. Circuit vacated the EPA’s denial of a Clean Air Act section 126 petition requesting that the Agency find approximately 350 sources of nitrogen oxides in nine States were contributing significantly to nonattainment in the New York Metropolitan Area. The court remanded the denial to EPA for further proceedings consistent with the court’s opinion. Mercury and Air Toxic Standards (MATS) . The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the NSPS for nitrogen oxides, SO 2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls. Following issuance of the final rule, numerous petitions for review were filed. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs against all challenges on April 15, 2014, in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. On June 29, 2015 the U.S. Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from power plants. The court reversed the D.C. Circuit and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision the EPA published a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision. On April 14, 2016, the EPA issued a final supplemental finding that largely tracked its proposed finding. Several states, companies and industry groups challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated (D.C. Cir. No. 116-1127). Several states and environmental groups also filed as intervenors for the respondent EPA. Although briefing in this litigation has concluded, the case remains in abeyance. On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule that would revoke the determination that regulating HAPs from coal-fired power plants is “appropriate and necessary” under Section 112(n)(1)(A) of the CAA. The proposed finding was based on an EPA assessment that health and environmental benefits from the MATS rule were not directly related to mercury pollution and should not be included in the benefit portion of the analysis. A final rule reversing EPA’s 2016 Supplemental Finding and determining, in lieu, that it is not “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants was promulgated in May 2020. 85 Fed. Reg. 31,286 (May 22, 2020). 58 Table of Contents Clean Water Act (CWA) . The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters. The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain permits from the Corps to place material in or mine through jurisdictional waters of the U.S. States are empowered to develop and apply water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Standards vary from state to state. Additionally, through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters. State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity. On June 1, 2020, the EPA issued a final rule intended to clarify the scope of the state or tribal regulators’ authority that would in effect limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections. New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the Clean Air Act’s Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) programs, generally referred to as NSR. On March 25, 2020, the EPA released a draft guidance document that would allow power plants, refineries and other sources of emissions to begin certain construction activities while still awaiting a permit under the NSR program. Under the EPA’s revised interpretation, a source owner or operator may, prior to obtaining a NSR permit, undertake physical on-site activities- including activities that may significantly alter the site, and/or are permanent in nature- provided that those activities do not constitute physical construction on an emissions unit. The comment period on the draft memo ended May 11, 2020. On August 4, 2020, EPA released a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the New Source Review Regulations). PALs allow sources to make physical and operational changes under a plantwide emission limit without “triggering” NSR. The EPA has also taken action on a number of different rules and guidance affecting the interpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA completed reconsideration of a 2009 petition to clarify when certain actions must be “aggregated” for purposes of determining whether these actions are part of a single project to which NSR applies. The EPA has additionally published guidance on the definition of “ambient air” (Revised Policy on Exclusions from “Ambient Air,” Dec. 2, 2019) and guidance concerning when multiple air pollution-emitting activities may be considered to be “adjacent” so that they should be considered to be a single source (Interpreting “Adjacent” for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas, Nov. 26, 2019). Additional memorandum and applicability determinations have also been made that address other NSR issues. These rules, guidance and memorandum may therefore affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis. Clean Water Act (CWA) Definition of “Waters of the United States”. A final rule defining the scope of waters protected under the CWA (commonly called the Waters of the United States, or WOTUS) (WOTUS Rule), was published by the EPA and the U.S. Army Corps of Engineers (Corps) in June 2015. Several states and others subsequently filed lawsuits challenging the 2015 WOTUS Rule, and eventually that rule was preliminarily enjoined in over half of the country. On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the 2015 WOTUS Rule and recodifying the regulatory definitions of WOTUS that existed prior to the implementation of the WOTUS Rule. On January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule to revise the definition of “Waters of the United States” and thereby establish the scope of federal regulatory authority under the CWA. A federal district judge in Colorado preliminarily enjoined the Navigable Waters Protection Rule in the State of Colorado on June 19, 2020. The new rule took effect in all other states on June 22, 2020, but the pre-2015 definitions apply in Colorado. 59 Table of Contents Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful. The Court vacated those portions of the rule. EPA has not yet determined how to address the vacated portions of the 2015 rule following the Fifth Circuit’s decision. Separately, on November 22, 2019, the EPA issued a proposed rule to revise 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. EPA finalized revised limits for those two wastewater streams on August 31, 2020, but those revisions have not yet been published in the Federal Register . As finalized, the revised effluent limitations guidelines could significantly increase costs for many coal-fired steam electric power plants. National Environmental Policy Act (NEPA) . NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. The final rule seeks to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. Proposed Rule for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country, and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for EPA’s proposal ended on April 20, 2020. EPA expects to issue a final rule in late 2020 or early 2021. Separately, on August 28, 2020, EPA finalized certain amendments to its 2015 CCR rule to partially address the U.S. Court of Appeals for the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective, EPA issued a proposed rule on March 3, 2020 to further revise the 2015 rule to address the remainder of the court decision, and EPA expects to issue a final rule in late 2020. Generally EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous. Regulatory Matters - Australia The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed. Native Title and Cultural Heritage . Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites. Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry. The Inquiry’s terms of reference include reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. The Inquiry is due to finalize its report by December 9, 2020. The Inquiry’s findings and resultant legislation, if any, could potentially impact the Company’s mining permits or existing mine plans in an effort to mitigate against adverse impacts to such sites. 60 Table of Contents Residual Risks. On August 20, 2020, the Environmental Protection and Other Legislation Amendment Act (Queensland) 2020 (EPOLA Act) became law amending the residual risk framework that aims to ensure that any remaining risks on former resource sites are appropriately identified, costed and managed. On completion of all mining activities, the holder of the Environmental Authority (EA) for the mine can apply to surrender the EA once all conditions, requirements and rehabilitation obligations have been met. When approving the surrender, the government can request a residual risk payment from the holder of the EA for the mine to cover potential rehabilitation or maintenance costs incurred after the surrender has been accepted. It contemplates two approaches for determining residual risk payments. Depending on the level of risk of a particular site, a cost calculator tool might be used or a panel of appropriately qualified experts might undertake a qualitative and quantitative risk assessment. Occupational Health and Safety . State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation. In September 2020, Safe Work Australia (SWA) published its revised Workplace Exposure Standards (WES) for coal dust and silica based on toxicological information and other monitoring data. SWA have recommended exposure limits of 1.5 mg/m 3 for coal dust (to apply from October 2022) and 0.05 mg/m 3 for silica (to apply as soon as possible). In Queensland, the new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m 3 )) took effect from July 1, 2020. In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m 3 commenced on July 1, 2020. The respirable coal dust workplace exposure standard of 2.5 mg/m 3 will be reduced to 1.5 mg/m 3 commencing on February 1, 2021 and mines will need to report exceedances of the new exposure standard to the NSW Resources Regulator from this commencement date. NSW will be the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard of 0.1 mg/m 3 to also commence on February 1, 2021. On July 1, 2020, the Resources Safety and Health Queensland Act 2020 became effective. It establishes Resources Safety and Health Queensland (RSHQ) as a statutory body designed to ensure independence of the mining safety and health regulator. RSHQ includes inspectorates for coal mines, mineral mines and quarries, explosives and petroleum and gas. The new law seeks to enhance the role of advisory committees to identify, quantify and prioritize safety and health issues in the mining and quarrying industries. It also provides for an independent Work Health and Safety Prosecutor to prosecute serious offenses under resources safety legislation. On May 20, 2020, the Queensland Parliament passed a bill into law that introduces the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are “senior officers” and companies in the mining industry. Individuals now face a maximum prison sentence of 20 years and companies could be fined up to approximately $13 million Australian dollars. This new law became effective July 1, 2020.The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity with an 18-month transition period ending November 25, 2021. Sydney Water Catchment Areas . In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning, Industry and Environment (DPIE) on the impact of underground mining activities in Sydney’s water catchment areas, including at our Metropolitan Mine. The Panel issued its final report in October 2019. The final report makes findings and recommendations concerning mining activities and effects across the catchment as a whole. The DPIE considered the recommendations in the Panel’s final report and in April 2020 announced that it had accepted all 50 recommendations in the Panel’s report, and that it has established an interagency taskforce to implement a detailed action plan during 2020. The action plan includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new independent expert panel to advise on future mining applications in the catchment; strengthening surface and groundwater monitoring; improving access to and transparency of environmental data; adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts; reviewing and updating current and potential future water losses from mining in line with the best available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine closure planning to reduce potential long-term impacts. 61 Table of Contents Queensland Royalties . As part of the Queensland Government’s 2019-20 Budget, the Government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contribute to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The Government contributes $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the Fund was approximately $713,000 Australian dollars for the 2019-20 financial year and is expected to decrease in years two and three based on an expected reduction in production at our Queensland mines. Liquidity and Capital Resources Overview Our primary source of cash is proceeds from the sale of our coal production to customers. We have also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under our credit facilities and, from time to time, the issuance of securities. Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, and selling and administrative expenses. We have also used cash for dividends, share repurchases and early debt retirements. Any future determinations to return capital to stockholders, such as dividends or share repurchases will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under our debt agreements, our net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. Our ability to declare dividends, repurchase shares or early retire debt in the future will depend on our future financial performance, which in turn depends on the successful implementation of our strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to our industry, many of which are beyond our control. We have presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds.” Liquidity As of September 30, 2020, our cash balances totaled $814.6 million, including approximately $652 million held by U.S. subsidiaries and $144 million held by Australian subsidiaries, approximately $69 million of which was held by the subsidiary which conducts the operations of our Wilpinjong Mine. Our remaining balance was held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by our foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. Our available liquidity declined from $1,275.8 million as of December 31, 2019 to $860.1 million as of September 30, 2020. Available liquidity as of October 31, 2020, September 30, 2020 and December 31, 2019 was comprised of the following: October 31, 2020 September 30, 2020 December 31, 2019 (Dollars in millions) Cash and cash equivalents $ 770.7 $ 814.6 $ 732.2 Revolving credit facility availability 11.5 5.1 498.6 Accounts receivable securitization program availability 45.8 40.4 45.0 Total liquidity $ 828.0 $ 860.1 $ 1,275.8 During the nine months ended September 30, 2020, the combined availability under our revolving credit facility and accounts receivable securitization program decreased as a result of $360.0 million of borrowings, $70.0 million of which was subsequently repaid, an additional $134.2 million of letters of credit issuances, and a $73.9 million reduction in available receivable balances under the accounts receivable securitization program. 62 Table of Contents We are party to various guarantees and financial instruments to provide support for our reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. At September 30, 2020, such instruments inclu ded $1,628.7 million face amount of surety bonds and $334.8 million of outstanding letters of credit. Subsequent to the filing of our Quarterly Report on Form 10-Q for the quarter ended June 30, 202 0 with the SEC on August 7, 2020, our counterparties have made various additional demands for collateral amounting to approximately $800 million. As further described below, we have reached an agreement with the majority of our surety bond providers to resolve these demands and limit future collateral requests. While we were compliant with the restrictions and covenants under our debt agreements at September 30, 2020, noncompliance with the first lien leverage ratio covenant under our Credit Agreement is probable as of December 31, 2020, if we do not successfully take mitigating actions. Absent waivers from the lenders under the Credit Agreement or other successful mitigating actions, noncompliance with the ratio covenant would constitute a default under the Credit Agreement, and the revolving lenders could elect to accelerate the maturity of the related indebtedness, or could potentially choose to exercise other rights and remedies under the agreement. Further, our senior secured notes, accounts receivable securitization program and certain lease agreements contain cross-default or termination provisions that would be triggered by an Event of Default as defined under the Credit Agreement, which could result in similar accelerations of those obligations. Accordingly, we have classified all such debt obligations and relevant lease liabilities as current in the accompanying condensed consolidated balance sheet as of September 30, 2020. The combined risks associated with our recent financial results, market conditions, additional collateral demands and potential Credit Agreement noncompliance raise substantial doubt about whether we will meet our obligations as they become due within one year from the date of issuance of these unaudited condensed consolidated financial statements and our ability to continue as a going concern. The accompanying unaudited condensed consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern. We are seeking to address the issues identified above by taking certain mitigating actions. As part of this process, we have entered into a transaction support agreement (TSA) in November 2020 with the providers of 99% of our surety bond portfolio (Participating Sureties) to define the parties’ commitments to implementing a transaction resolving approximately $800 million in additional collateral demands made by the Participating Sureties. Among other things, the TSA includes the following terms and conditions: • Under the terms of the TSA, we will post $75.0 million of collateral, a minimum of $40.0 million of which will be in the form of letters of credit, and provide second liens on $200.0 million of certain mining equipment for the benefit of the Participating Sureties.. • In addition, we will post an additional $25.0 million of collateral per year through 2025 for the benefit of the Participating Sureties. The collateral postings will also further increase to the extent we generate more than $100.0 million of free cash flow (as defined in the TSA) in any twelve-month period or have asset sales in excess of $10.0 million. • The Participating Sureties have agreed to a standstill through the earlier of December 2025 or the maturity date of the Credit Agreement (as amended or refinanced). During which time, the Participating Sureties agree not to demand any additional collateral, draw on letters of credit posted for the benefit of themselves, or cancel, or attempt to cancel, any existing surety bond. In addition, we have been engaged in discussions with our revolving credit lenders and the holders of our 2022 Notes (as defined in Note 12. “Long-term Debt”) (the 2022 Noteholders) with the primary objectives of covenant relief and the extension of maturity dates, while maintaining financial flexibility. The TSA described above is contingent upon an agreement between Peabody, our revolving credit lenders, and the 2022 Noteholders accomplishing those objectives by December 31, 2020, which can be extended at our discretion to January 29, 2021 for purposes of increasing participation. Further, we are working to improve our liquidity and financial position through other means such as the sale of nonstrategic surplus land, coal reserves, and other assets, and driving cost improvements across our operations. However, there can be no assurance that we will be able to obtain a waiver of noncompliance or otherwise amend the Credit Agreement to address covenant issues, reach agreement on the comprehensive approach to address our combined liquidity risks described above, or improve our overall liquidity and financial position through other means. As a result, our ability to timely meet our obligations when due or satisfy additional collateral demands could be adversely affected. If we are not able to timely, successfully, or efficiently implement the strategies that we are pursuing to address those risks and improve our liquidity and financial position, or otherwise meet our liquidity needs, we may need to voluntarily pursue an in-court restructuring. 63 Table of Contents Debt Financing As described in Note 12. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, during 2017, we entered into an indenture related to the issuance of $500.0 million of 6.000% senior secured notes due March 2022 and $500.0 million of 6.375% senior secured notes due March 2025. We make semi-annual interest payments on the senior notes each March 31 and September 30 until maturity. Also during 2017, we entered into a credit agreement (the Credit Agreement) and related term loan under which we originally borrowed $950.0 million and have repaid $560.0 million through September 30, 2020. The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025. We entered into the revolving credit facility allowable under our Credit Agreement during 2017 for an aggregate commitment of $350.0 million for general corporate purposes. In September 2019, we entered into an amendment to the Credit Agreement which increased the aggregate commitment amount under the revolver to $565.0 million and, beginning in 2020, made applicable interest rates and fees dependent upon our periodically-determined first lien leverage ratio, as defined in the Credit Agreement. To date, we have utilized the revolving credit facility to borrow $300.0 million during the second quarter of 2020, of which we subsequently repaid $70.0 million during the third quarter of 2020, and for letters of credit which incur combined fees of 3.125%, while unused capacity bears a commitment fee of 0.4%. As of September 30, 2020, such letters of credit amounted to $329.9 million and were primarily in support of our reclamation obligations. At September 30, 2020 , the remaining availability under the revolving credit facility was $5.1 million . Our debt agreements impose various restrictions and limits on certain categories of payments that we may make, such as those for dividends, investments, and stock repurchases. We are also subject to customary affirmative and negative covenants, such as the first lien leverage ratio covenant described above. We were in compliance with all such restrictions and covenants at September 30, 2020. Accounts Receivable Securitization Program As described in Note 17. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, we entered into an amended accounts receivable securitization program during 2017 which currently expires in 2022. The program provides for up to $250.0 million in funding, limited to the availability of eligible receivables, accounted for as a secured borrowing. Funding capacity under the program may also be provided for letters of credit in support of other obligations. At September 30, 2020, we h a d $60.0 million in outstanding borrowings and $3.4 million of letters of credit provided under the program. The letters of credit are primarily in support of portions of our obligations for property and casualty insurance. Availability under the program, which is adjusted for certain ineligible receivables, was $40.4 million at September 30, 2020 and there was no cash collateral requirement. Capital Requirements As a result of the deferral of certain capital project spending to subsequent periods, we revised our expected 2020 capital expenditures to approximately $200 million during the second quarter of 2020, as compared to approximately $250 million as disclosed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2019. There have been no other material changes to our capital requirements. Contractual Obligations As a result of the changes to one of our postretirement health care benefit plans as described in Note 13. “Pension and Postretirement Benefit Costs,” we expect reductions in benefits payments of approximately $5 million during 2021, approximately $16 million during the two-year period ending December 31, 2023, approximately $18 million during the two-year period ending December 31, 2025, and approximately $210 million thereafter. There were no material changes to our contractual obligations from the information previously provided in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2019, and in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020. 64 Table of Contents Historical Cash Flows and Free Cash Flow The following table summarizes our cash flows for the nine months ended September 30, 2020 and 2019, 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, 2020 2019 (Dollars in millions) Net cash (used in) provided by operating activities $ (32.1) $ 552.6 Net cash used in investing activities (159.4) (147.6) Net cash provided by (used in) financing activities 273.9 (610.0) Net change in cash, cash equivalents and restricted cash 82.4 (205.0) Cash, cash equivalents and restricted cash at beginning of period 732.2 1,017.4 Cash, cash equivalents and restricted cash at end of period $ 814.6 $ 812.4 Net cash (used in) provided by operating activities $ (32.1) $ 552.6 Net cash used in investing activities (159.4) (147.6) Add back: Amount attributable to acquisition of Shoal Creek Mine — 2.4 Free Cash Flow $ (191.5) $ 407.4 Operating Activities. The net decrease in net cash (used in) provided by operating activities for the nine months ended September 30, 2020 compared to the same period in the prior year was driven by a year-over-year decrease in cash from our mining operations, partially offset by a favorable change in net cash flows associated with our working capital ($30.4 million), and higher funding of our pension and retiree healthcare plans during the prior year period ($37.0 million). Investing Activities. The increase in net cash used in investing activities for the nine months ended September 30, 2020 compared to the same period in the prior year was driven by higher proceeds from the disposal of assets and from insurance recoveries attributable to North Goonyella equipment in the prior year period ($35.4 million) and higher cash receipts from Middlemount in the prior year period ($14.7 million), partially offset by lower capital expenditures in the current year period ($41.6 million). Financing Activities. The increase in net cash provided by (used in) financing activities for the nine months ended September 30, 2020 compared to the same period in the prior year was driven common stock repurchases ($300.2 million) and the payment of dividends, including a supplemental dividend of $1.85 per share of common stock ($243.9 million) during the prior year period and current year borrowings under our revolving credit facility and accounts receivable securitization program ($300.0 million and $60.0 million, respectively), partially offset by higher long-term debt repayments in the current year ($57.1 million). Off-Balance Sheet Arrangements In the normal course of business, we are a party to various guarantees and financial instruments that carry off-balance sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At September 30, 2020, such instruments inc luded $1,628.7 million of surety bonds and $334.8 million o f letters of credit. These financial instruments provide support for our reclamation bonding requirements, lease obligations, insu rance policies and various other performance guarantees. We periodically evaluate the instruments for on-balance sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. We do not expect any material losses to result from these guarantees or off-balance sheet instruments in excess of liabilities provided for in our condensed consolidated balance sheets. 65 Table of Contents As of September 30, 2020, the Company was party to financial instruments with off-balance sheet risk in support of the following obligations: Reclamation Health and welfare (1) Contract performance (2) Leased property and equipment Other (3) Total (Dollars in millions) Surety bonds and bank guarantees $ 1,439.8 $ 55.9 $ 78.8 $ 38.3 $ 15.9 $ 1,628.7 Letters of credit outstanding under revolving credit facility 235.9 85.6 3.4 5.0 — 329.9 Letters of credit outstanding under accounts receivable securitization program — 3.1 0.3 — — 3.4 Other letters of credit — 1.5 — — — 1.5 1,675.7 146.1 82.5 43.3 15.9 1,963.5 Less: collateral letters of credit (4) (235.9) (26.1) — — — (262.0) Obligations supported, net $ 1,439.8 $ 120.0 $ 82.5 $ 43.3 $ 15.9 $ 1,701.5 (1) Obligations include pension and healthcare plans, workers’ compensation, and property and casualty insurance (2) Obligations pertain to customer and vendor contracts (3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration (4) Serve as collateral for certain surety bonds at the request of surety bond providers We could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, surety bonds or other obligations are required to be collateralized by cash or letters of credit. Our surety bond providers have the ability to demand collateral up to the full amount of each surety bond. As described in Note 17. “Financial Instruments and Other Guarantees” in the accompanying unaudited condensed consolidated financial statements, we are required to provide various forms of financial assurance in support of our mining reclamation obligations in the jurisdictions in which we operate. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. Self-bonding in the U.S. has become increasingly restricted in recent years, leading to our increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on our liquidity due to increased collateral requirements and surety and related fees. At September 30, 2020, we had total asset retirement obligations of $762.8 million which were backed by a combination of surety bonds 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 our accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date. Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 17. “Financial Instruments and Other Guarantees” in our unaudited condensed consolidated financial statements for a discussion of our accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk. Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. We are also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. 66 Table of Contents Impairment of Long-Lived Assets . We recognized an asset impairment charge of $1,418.1 million during the nine months ended September 30, 2020 related to our North Antelope Rochelle Mine of the Powder River Basin Mining segment. The outlook for the North Antelope Rochelle Mine has been negatively impacted by the accelerated decline of coal-fired electricity generation in the U.S., driven by the reduced utilization of plants and plant retirements, sustained low natural gas pricing, and the increased use of renewable energy sources. These factors have led to the expectation of reduced future sales volumes. The impairment charge was based upon the remaining estimated discounted cash flows of the mine. Such cash flows were based upon estimates which generally constitute unobservable Level 3 inputs under the fair value hierarchy, including, but not limited to, future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, and a risk-adjusted, cost of capital. At September 30, 2020, we also identified certain assets with an aggregate carrying value of approximately $1.1 billion in our 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. We conducted a review of those assets for recoverability as of September 30, 2020 and determined that no further impairment charges were necessary as of that date. See Note 9. “Property, Plant, Equipment and Mine Development” to our accompanying unaudited condensed consolidated financial statements for additional information regarding impairment charges. Postretirement Benefit Liabilities . During September 2020, we announced changes to one of our postretirement health care benefit plans. Effective January 1, 2021, we will no longer subsidize medical costs for Medicare eligible individuals or provide life insurance to retirees. We will provide non-Medicare eligible retirees and eligible dependents a health reimbursement arrangement. We recorded a mark-to-market loss of $13.0 million during the three and nine months ended September 30, 2020, primarily due to the decrease in discount rate, and reduced our accumulated postretirement benefit obligation by $174.5 million as the result of the elimination of health care benefits upon covered individuals’ attainment of Medicare eligibility. The changes represented a remeasurement event that required us to consider various actuarial assumptions, including the discount rate, future cost trends, demographic assumptions and expected asset returns to estimate the costs and obligations for these items. See Note 13. “Pension and Postretirement Benefit Costs” to our accompanying unaudited condensed consolidated financial statements for additional information regarding the changes to one of our postretirement health care benefit plans. Our critical accounting policies are discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019. Our critical accounting policies remain unchanged at September 30, 2020. Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to our unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.