BTU filing — read by section

Item 2. Management’s Discussion and Analysis

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
 
 As used in this report, the terms “Peabody” or “the Company” refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the Company’s continuing operations. 
 When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms). 
 Cautionary Notice Regarding Forward-Looking Statements 
 This report includes statements of Peabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or Peabody’s future financial performance. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements. 
 Without limiting the foregoing, all statements relating to Peabody’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that Peabody believes are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond the Company’s control. 
 When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in the Company’s other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect its results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of its Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 18, 2022. These forward-looking statements speak only as of the date on which such statements were made, and the Company undertakes no obligation to update these statements except as required by federal securities laws. 
 
 Non-GAAP Financial Measures 
 The following discussion of the Company’s results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of its segments’ operating performance and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance. 
 Also included in the following discussion of the Company’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of its mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2. 
 In its discussion of liquidity and capital resources, the Company includes references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of its financial performance and its ability to generate excess cash flow from its business operations. 
 The Company believes non-GAAP performance measures are used by investors to measure its operating performance and lenders to measure its ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP. 
 
 
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 Overview 
 Peabody is a leading producer of metallurgical and thermal coal. In 2021, the Company produced and sold 126.9 million and 130.1 million tons of coal, respectively, from continuing operations. At June 30, 2022, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to its mining operations, the Company markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts. 
 The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other. Refer to Note 14. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of its Corporate and Other segment. 
 Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended June 30, 2022 is set forth in the table below. 
 The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2022 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a bi-annual, quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. 
 In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2022 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing. 
 
 High Low Average June 30, 2022 July 29, 2022 
 Premium HCC (1) 
 $ 530.25 $ 302.00 $ 445.52 $ 302.00 $ 191.00 
 Premium PCI coal (1) 
 517.25 275.50 419.63 275.50 182.50 
 Newcastle index thermal coal (1) 
 436.07 271.05 372.90 390.68 420.88 
 API 5 index thermal coal (1) 
 204.38 181.93 194.74 190.00 214.12 
 PRB 8,800 Btu/Lb coal (2) 
 17.50 15.80 16.61 16.55 18.20 
 Illinois Basin 11,500 Btu/Lb coal (2) 
 170.00 126.00 142.00 170.00 180.00 

 (1) Prices expressed per metric tonne. 
 (2) Prices expressed per short ton. 
 Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the ongoing Russian-Ukrainian conflict and the coronavirus (COVID-19) pandemic. Furthermore, inflationary pressures have contributed to rising costs and may continue to rise in future periods. As future developments related to the Russian-Ukrainian conflict, the COVID-19 pandemic and rising inflation are unknown, the global coal industry data for the six months ended June 30, 2022 presented herein may not be indicative of their ultimate impacts. 
 
 
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 Within the seaborne metallurgical coal market, the three months ended June 30, 2022 were characterized by significant volatility, primarily driven by a weakening global macroeconomic environment and trade disruptions following sanctions imposed on Russian coal imports. Steel prices weakened in the three months ended June 30, 2022, causing some steelmakers to consider output cuts in the coming period. This is influencing short-term incremental metallurgical coal demand; however, it is being counteracted by steelmakers in Atlantic markets seeking to mitigate exposure to Russian coal imports, causing increased demand for supply from other regions such as Australia, the U.S. and Canada. This is particularly so for PCI, where Russia accounts for approximately 35% of global traded volumes. China’s unofficial ban on Australian coal remains in place and continues to disrupt traditional trade flows. The Company believes energy shortages in some markets present a risk to industrial activity, but the underlying market fundamentals remain constructive. 
 Within the seaborne thermal coal market, global thermal coal prices continue to remain at near-record levels, fueled by broader energy supply security concerns. These concerns have been driven by the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries, as well as weather and COVID impacts limiting supply response out of Australia. In China, domestic coal production and renewable generation growth have been strong during the six months ended June 30, 2022, which has lowered import demand to start the year. In India, elevated domestic coal production has limited import demand, allowing coal buyers to wait for lower thermal seaborne prices. Overall, global thermal coal markets remain turbulent as supply remains tight and European coal importers look to replace Russian coal. 
 In the United States, overall electricity demand increased more than 4% year-over-year, positively impacted by weather and economic activity. Through the six months ended June 30, 2022, electricity generation from thermal coal has declined year-over-year due to coal conservation by utilities to build coal stocks ahead of summer, strong year-over-year comparatives in February 2021 and record renewable generation. Coal’s share of electricity generation has declined slightly to approximately 20% for the six months ended June 30, 2022, while wind generation’s share has increased to 11%. Coal inventories have continued to decline since December 2021, with a decline of approximately 7% or 7 million tons. During the six months ended June 30, 2022, utility consumption of PRB coal declined approximately 2% compared to the prior year period. 
 Financing Transactions 
 During the first quarter of 2022, Peabody issued convertible senior unsecured notes and used the proceeds of the offering to retire nearer term higher cost senior secured debt. This both lowered the Company’s borrowing rates and extended debt maturities to 2028. During the second quarter of 2022, Peabody continued to reduce it outstanding debt, with additional retirements pending settlement after the balance sheet date. 
 High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices in the first half of 2022, which has been amplified by the Russian-Ukrainian conflict, resulting in unprecedented upward volatility in Newcastle coal pricing since late February. As a result, Peabody posted additional cash margin of $414.1 million during the six months ended June 30, 2022 to satisfy the margin requirements for its derivative contracts. 
 Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of these financing and liquidity transactions. 
 Other 
 In March 2022, the Company entered into a joint venture with unrelated partners to form R3 Renewables LLC (R3). R3 was formed with the intent of developing various sites, including certain non-mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage. During the second quarter of 2022, R3 advanced efforts with potential customers, finalized its management team and commenced site evaluations with project developer Treaty Oak Clean Energy, LLC. The Company’s interest in R3 is accounted for as an equity method investment. The Company contributed $2.5 million to R3 and recorded an equity loss of $1.8 million from its operations during the six months ended June 30, 2022. 
 
 
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 In March 2022, Peabody Investments Corp., a wholly owned subsidiary of the Company, entered into a commitment agreement relating to one of its qualified pension plans (the Plan) with an insurer. Under the commitment agreement, the Plan purchased a group annuity contract for approximately $500 million and the insurer will reimburse the Plan for future benefit payments to be made to the Plan’s participants. Under the terms of this transaction, the Plan will continue to administer and pay the retirement benefits of Plan participants but will be reimbursed by the insurer for the payment of all benefits covered by the group annuity contract. In May 2022, the board of directors of Peabody Investments Corp. approved commencing a standard Employee Retirement Income Security Act plan termination with an effective date of plan termination of July 31, 2022. Refer to Note 10. “Pension and Postretirement Benefit Costs” to the accompanying unaudited condensed consolidated financial statements for a further discussion of this transaction. 
 
 Results of Operations 
 Three and Six Months Ended June 30, 2022 Compared to the Three and Six Months Ended June 30, 2021 
 Summary 
 The increases in results from continuing operations, net of income taxes for the three and six months ended June 30, 2022 compared to the same periods in the prior year ($434.3 million and $392.2 million, respectively), were primarily driven by higher revenue ($598.5 million and $638.6 million, respectively) due to higher realized prices; improved results from equity affiliates ($52.2 million and $97.8 million, respectively); and lower interest expense ($7.8 million and $20.8 million, respectively). These favorable variances were partially offset by higher operating costs and expenses ($214.2 million and $330.6 million, respectively), which reflect increased sales sensitive costs, inflationary pressures for materials, services, repairs and labor; and net losses on early debt extinguishments in the current year ($14.1 million and $41.1 million, respectively). 
 Adjusted EBITDA for the three and six months ended June 30, 2022 reflected year-over-year increases of $455.7 million and $722.1 million, respectively. 
 
 Tons Sold 
 The following table presents tons sold by operating segment: 
 
 Three Months Ended June 30, (Decrease) Increase
to Volumes Six Months Ended June 30, (Decrease) Increase
to Volumes 
 2022 2021 Tons % 2022 2021 Tons % 
 (Tons in millions) (Tons in millions) 
 Seaborne Thermal Mining 4.0 4.1 (0.1) (2) % 7.8 8.2 (0.4) (5) % 
 Seaborne Metallurgical Mining 
 1.6 1.4 0.2 14 % 2.8 2.4 0.4 17 % 
 Powder River Basin Mining 18.5 22.5 (4.0) (18) % 39.1 43.2 (4.1) (9) % 
 Other U.S. Thermal Mining 4.4 3.9 0.5 13 % 8.6 7.8 0.8 10 % 
 Total tons sold from mining segments 
 28.5 31.9 (3.4) (11) % 58.3 61.6 (3.3) (5) % 
 Corporate and Other 0.1 0.9 (0.8) (89) % 0.2 1.4 (1.2) (86) % 
 Total tons sold 28.6 32.8 (4.2) (13) % 58.5 63.0 (4.5) (7) % 

 
 
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 Supplemental Financial Data 
 The following table presents supplemental financial data by operating segment: 
 
 Three Months Ended June 30, Increase 
(Decrease) Six Months Ended June 30, Increase 
(Decrease) 
 2022 2021 $ % 2022 2021 $ % 
 Revenue per Ton - Mining Operations (1) 
 
 Seaborne Thermal $ 87.37 $ 46.92 $ 40.45 86 % $ 77.52 $ 45.15 $ 32.37 72 % 
 Seaborne Metallurgical 330.56 85.48 245.08 287 % 299.82 86.31 213.51 247 % 
 Powder River Basin 12.44 11.06 1.38 12 % 12.30 11.04 1.26 11 % 
 Other U.S. Thermal 51.40 40.70 10.70 26 % 49.96 39.75 10.21 26 % 
 Costs per Ton - Mining Operations (1)(2) 
 
 Seaborne Thermal $ 43.85 $ 29.61 $ 14.24 48 % $ 43.33 $ 32.97 $ 10.36 31 % 
 Seaborne Metallurgical 144.91 104.24 40.67 39 % 131.26 106.51 24.75 23 % 
 Powder River Basin 12.55 9.04 3.51 39 % 12.16 9.29 2.87 31 % 
 Other U.S. Thermal 37.25 29.57 7.68 26 % 36.90 29.47 7.43 25 % 
 Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) 
 
 Seaborne Thermal $ 43.52 $ 17.31 $ 26.21 151 % $ 34.19 $ 12.18 $ 22.01 181 % 
 Seaborne Metallurgical 185.65 (18.76) 204.41 1,090 % 168.56 (20.20) 188.76 934 % 
 Powder River Basin (0.11) 2.02 (2.13) (105) % 0.14 1.75 (1.61) (92) % 
 Other U.S. Thermal 14.15 11.13 3.02 27 % 13.06 10.28 2.78 27 % 

 (1) This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. 
 (2) Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. 
 Revenue 
 The following table presents revenue by reporting segment: 
 
 Three Months Ended June 30, Increase (Decrease) to Revenue Six Months Ended June 30, Increase (Decrease) to Revenue 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Seaborne Thermal Mining $ 354.9 $ 194.1 $ 160.8 83 % $ 606.1 $ 370.5 $ 235.6 64 % 
 Seaborne Metallurgical Mining 
 533.8 121.0 412.8 341 % 855.1 208.5 646.6 310 % 
 Powder River Basin Mining 229.7 248.6 (18.9) (8) % 480.9 477.0 3.9 1 % 
 Other U.S. Thermal Mining 224.9 162.1 62.8 39 % 428.0 311.4 116.6 37 % 
 Corporate and Other (21.4) (2.4) (19.0) (792) % (356.8) 7.3 (364.1) (4,988) % 
 Revenue $ 1,321.9 $ 723.4 $ 598.5 83 % $ 2,013.3 $ 1,374.7 $ 638.6 46 % 

 Seaborne Thermal Mining. Segment revenue increased during the three months ended June 30, 2022 compared to the same period in the prior year due to favorable realized prices ($156.8 million) and favorable mix variances ($4.0 million) resulting from higher export volumes. Segment revenue increased during the six months ended June 30, 2022 compared to the same period in the prior year primarily due to favorable realized prices ($271.9 million), offset by unfavorable volumes ($36.3 million) which were impacted by a longwall move at the Wambo Underground Mine, wet weather and COVID-19-related staffing shortages. 
 Seaborne Metallurgical Mining. Segment revenue increased during the three and six months ended June 30, 2022 compared to the same periods in the prior year due to favorable realized prices ($279.8 million and $470.0 million, respectively) and favorable volume and mix variances ($133.0 million and $176.6 million, respectively). 
 
 
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 Powder River Basin Mining. Segment revenue decreased during the three months ended June 30, 2022 compared to the same period in the prior year due to unfavorable volumes ($43.2 million) resulting from rail performance issues, partially offset by favorable realized prices ($24.3 million). Segment revenue increased during the six months ended June 30, 2022 compared to the same period in the prior year due to favorable realized coal pricing ($51.3 million), offset by unfavorable volumes ($47.4 million). 
 Other U.S. Thermal Mining. Segment revenue increased during the three and six months ended June 30, 2022 compared to the same periods in the prior year due to favorable realized prices ($48.6 million and $88.6 million, respectively) and favorable volumes ($14.2 million and $28.0 million, respectively). 
 Corporate and Other. Segment revenue decreased during the three months ended June 30, 2022 compared to the same period in the prior year primarily due to lower results from trading activities ($22.5 million). Segment revenue decreased during the six months ended June 30, 2022 compared to the same period in the prior year due to increased net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales ($299.9 million) and lower results from trading activities ($70.6 million). 
 
 Adjusted EBITDA 
 The following table presents Adjusted EBITDA for each of the Company’s reporting segments: 
 
 Three Months Ended June 30, Increase (Decrease) to Segment Adjusted EBITDA Six Months Ended June 30, Increase (Decrease) to Segment Adjusted EBITDA 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Seaborne Thermal Mining 
 $ 176.8 $ 71.4 $ 105.4 148 % $ 267.3 $ 99.9 $ 167.4 168 % 
 Seaborne Metallurgical Mining 
 299.7 (26.4) 326.1 1,235 % 480.7 (48.8) 529.5 1,085 % 
 Powder River Basin Mining (2.0) 45.5 (47.5) (104) % 5.6 75.6 (70.0) (93) % 
 Other U.S. Thermal Mining 61.9 44.3 17.6 40 % 111.9 80.5 31.4 39 % 
 Corporate and Other 41.4 (12.7) 54.1 426 % 39.8 (24.0) 63.8 266 % 
 Adjusted EBITDA (1) 
 $ 577.8 $ 122.1 $ 455.7 373 % $ 905.3 $ 183.2 $ 722.1 394 % 

 (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. 
 Seaborne Thermal Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2022 compared to the same periods in the prior year as a result of higher realized prices net of sales sensitive costs ($143.8 million and $249.7 million, respectively), partially offset by unfavorable operational costs ($48.5 million and $87.5 million, respectively) resulting from the impacts of wet weather, COVID-19-related staffing shortages, the longwall move at the Wambo Underground Mine and inflationary pressures. 
 Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2022 compared to the same periods in the prior year due to higher realized prices net of sales sensitive costs ($241.8 million and $408.2 million, respectively) and favorable volumes, offset by higher costs resulting from longwall panel transitions at the Shoal Creek Mine and inflationary pressures across the segment. 
 Powder River Basin Mining. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2022 compared to the same periods in the prior year due to lower volumes ($23.4 million in both periods) resulting from rail performance issues; the unfavorable impacts of higher commodity pricing ($19.0 million and $33.6 million, respectively) and higher costs for materials, services, repairs and labor ($18.7 million and $42.8 million, respectively), both of which were impacted by inflationary pressures; and elevated overburden removal costs. These decreases were partially offset by higher prices net of sales sensitive costs ($24.8 million and $51.9 million, respectively). 
 Other U.S. Thermal Mining. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2022 compared to the same periods in the prior year due to higher realized prices net of sales sensitive costs ($50.1 million and $91.5 million, respectively) and favorable volumes ($6.2 million and $13.0 million, respectively). These increases were offset by higher costs for materials, services, repairs and labor ($23.5 million and $49.4 million, respectively) and the unfavorable impacts of higher commodity pricing ($14.5 million and $24.4 million, respectively), both of which were impacted by inflationary pressures. 
 
 
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 Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: 
 
 Three Months Ended June 30, Increase (Decrease) to Adjusted EBITDA Six Months Ended June 30, Increase (Decrease) to Adjusted EBITDA 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Middlemount (1) 
 $ 48.9 $ (4.1) $ 53.0 1,293 % $ 94.0 $ (6.4) $ 100.4 1,569 % 
 Resource management 
 activities (2) 
 13.8 3.9 9.9 254 % 17.3 4.3 13.0 302 % 
 Selling and administrative expenses 
 (21.8) (21.4) (0.4) (2) % (44.9) (43.1) (1.8) (4) % 
 Other items, net (3) 
 0.5 8.9 (8.4) (94) % (26.6) 21.2 (47.8) (225) % 
 Corporate and Other Adjusted EBITDA 
 $ 41.4 $ (12.7) $ 54.1 426 % $ 39.8 $ (24.0) $ 63.8 266 % 

 (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 $23.3 million and $3.7 million during the three months ended June 30, 2022 and 2021, respectively, and $43.5 million and $7.9 million during the six months ended June 30, 2022 and 2021, respectively. 
 (2) Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenue. 
 (3) Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and expenses related to the Company’s other commercial activities. 
 Corporate and Other Adjusted EBITDA benefited during the three and six months ended June 30, 2022 compared to the same period in the prior year from favorable variances in Middlemount’s results due to the impact of higher sales pricing ($53.0 million and $100.4 million, respectively) and gains on various land sales in both the U.S. and Australia ($11.5 million and $12.6 million, respectively). This benefit was largely offset by unfavorable trading results ($12.1 million and $54.0 million, respectively). 
 
 
 
 
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 Income (Loss) From Continuing Operations, Net of Income Taxes 
 The following table presents income (loss) from continuing operations, net of income taxes: 
 
 Three Months Ended June 30, Increase (Decrease) to Income Six Months Ended June 30, Increase (Decrease) to Income 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Adjusted EBITDA (1) 
 $ 577.8 $ 122.1 $ 455.7 373 % $ 905.3 $ 183.2 $ 722.1 394 % 
 Depreciation, depletion and amortization (73.8) (77.1) 3.3 4 % (146.7) (145.4) (1.3) (1) % 
 Asset retirement obligation expenses (12.7) (15.1) 2.4 16 % (27.7) (31.0) 3.3 11 % 
 Restructuring charges (0.2) (2.1) 1.9 90 % (1.8) (4.2) 2.4 57 % 
 
 
 
 
 Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 0.6 0.5 0.1 20 % 1.2 2.0 (0.8) (40) % 
 Interest expense (37.6) (45.4) 7.8 17 % (77.0) (97.8) 20.8 21 % 
 Net (loss) gain on early debt extinguishment (2.3) 11.8 (14.1) (119) % (25.8) 15.3 (41.1) (269) % 
 Interest income 0.9 1.3 (0.4) (31) % 1.4 2.8 (1.4) (50) % 
 
 Unrealized losses on derivative contracts related to forecasted sales 
 (24.5) (23.7) (0.8) (3) % (325.5) (25.6) (299.9) (1,171) % 
 Unrealized losses on foreign currency option contracts (6.3) (1.2) (5.1) (425) % (3.0) (8.8) 5.8 66 % 
 Take-or-pay contract-based intangible recognition 0.7 1.1 (0.4) (36) % 1.4 2.2 (0.8) (36) % 
 Income tax (provision) benefit (11.3) 4.8 (16.1) (335) % (10.3) 6.6 (16.9) (256) % 
 Income (loss) from continuing operations, net of income taxes $ 411.3 $ (23.0) $ 434.3 1,888 % $ 291.5 $ (100.7) $ 392.2 389 % 

 (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. 
 Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment: 
 
 Three Months Ended June 30, Increase (Decrease) to Income Six Months Ended June 30, (Decrease) Increase to Income 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Seaborne Thermal Mining 
 $ (26.2) $ (26.9) $ 0.7 3 % $ (50.2) $ (48.0) $ (2.2) (5) % 
 Seaborne Metallurgical Mining 
 (22.0) (17.4) (4.6) (26) % (41.9) (33.9) (8.0) (24) % 
 Powder River Basin Mining 
 (9.3) (10.3) 1.0 10 % (19.8) (19.9) 0.1 1 % 
 Other U.S. Thermal Mining 
 (13.7) (16.0) 2.3 14 % (29.4) (33.2) 3.8 11 % 
 Corporate and Other 
 (2.6) (6.5) 3.9 60 % (5.4) (10.4) 5.0 48 % 
 Total $ (73.8) $ (77.1) $ 3.3 4 % $ (146.7) $ (145.4) $ (1.3) (1) % 

 
 
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 Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its mining segments: 
 
 Three Months Ended June 30, Six Months Ended June 30, 
 2022 2021 2022 2021 
 Seaborne Thermal Mining $ 2.46 $ 2.47 $ 2.47 $ 2.17 
 Seaborne Metallurgical Mining 
 3.42 1.03 2.85 1.02 
 Powder River Basin Mining 0.32 0.24 0.32 0.24 
 Other U.S. Thermal Mining 
 1.24 1.17 1.21 1.15 

 The increase in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three and six months ended June 30, 2022 compared to the same period in the prior year reflects the impact of the resumption of sales at the Shoal Creek Mine. 
 Interest Expense. The decrease in interest expense during the three and six months ended June 30, 2022 primarily reflects the impacts of debt retirements completed by the Company during 2022 and 2021 and prior year fees related to a series of refinancing transactions completed by the Company (six months, $10.6 million) as further described in Note 9. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements and Note 11. “Long-term Debt” to the Annual Report on Form 10-K for the year ended December 31, 2021. 
 Net (Loss) Gain on Early Debt Extinguishment. The losses recognized during the three and six months ended June 30, 2022 were primarily related to the redemption of existing notes during the periods as further discussed in Note 9. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements. 
 Unrealized Losses on Derivative Contracts Related to Forecasted Sales. Unrealized losses primarily relate to mark-to-market activity on derivatives related to forecasted sales. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. 
 Unrealized Losses on Foreign Currency Option Contracts. Unrealized losses primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. 
 Income Tax (Provision) Benefit. The increase in the income tax provision during the three and six months ended June 30, 2022 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 benefit related to the remeasurement of foreign income tax accounts. The Company expects to utilize substantial net operating losses in Australia and the U.S. in 2022 based on estimated pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information. 
 
 Net Income (Loss) Attributable to Common Stockholders 
 The following table presents net income (loss) attributable to common stockholders: 
 
 Three Months Ended June 30, Increase (Decrease)
to Income Six Months Ended June 30, Increase (Decrease)
to Income 
 2022 2021 $ % 2022 2021 $ % 
 (Dollars in millions) (Dollars in millions) 
 Income (loss) from continuing operations, net of income taxes $ 411.3 $ (23.0) $ 434.3 1,888 % $ 291.5 $ (100.7) $ 392.2 389 % 
 Loss from discontinued operations, net of income taxes (0.7) (2.3) 1.6 70 % (1.5) (4.3) 2.8 65 % 
 Net income (loss) 410.6 (25.3) 435.9 1,723 % 290.0 (105.0) 395.0 376 % 
 Less: Net income attributable to noncontrolling interests 1.1 3.3 (2.2) (67) % — 3.7 (3.7) (100) % 
 Net income (loss) attributable to common stockholders $ 409.5 $ (28.6) $ 438.1 1,532 % $ 290.0 $ (108.7) $ 398.7 367 % 

 
 
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 Diluted Earnings per Share (EPS) 
 The following table presents diluted EPS: 
 
 Three Months Ended June 30, Increase 
to EPS Six Months Ended June 30, Increase 
to EPS 
 2022 2021 $ % 2022 2021 $ % 
 Diluted EPS attributable to common stockholders: 
 
 Income (loss) from continuing operations $ 2.55 $ (0.26) $ 2.81 1,081 % $ 1.93 $ (1.05) $ 2.98 284 % 
 Loss from discontinued operations (0.01) (0.02) 0.01 50 % — (0.04) 0.04 100 % 
 Net income (loss) attributable to common stockholders $ 2.54 $ (0.28) $ 2.82 1,007 % $ 1.93 $ (1.09) $ 3.02 277 % 

 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 161.9 million and 101.2 million for the three months ended June 30, 2022 and 2021, respectively, and 152.5 million and 99.8 million for the six months ended June 30, 2022 and 2021, respectively. 
 
 Reconciliation of Non-GAAP Financial Measures 
 Adjusted EBITDA is defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below. 
 
 Three Months Ended June 30, Six Months Ended June 30, 
 2022 2021 2022 2021 
 (Dollars in millions) 
 Income (loss) from continuing operations, net of income taxes $ 411.3 $ (23.0) $ 291.5 $ (100.7) 
 Depreciation, depletion and amortization 
 73.8 77.1 146.7 145.4 
 Asset retirement obligation expenses 
 12.7 15.1 27.7 31.0 
 Restructuring charges 
 0.2 2.1 1.8 4.2 
 
 
 
 
 Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 
 (0.6) (0.5) (1.2) (2.0) 
 Interest expense 
 37.6 45.4 77.0 97.8 
 Net loss (gain) on early debt extinguishment 2.3 (11.8) 25.8 (15.3) 
 Interest income 
 (0.9) (1.3) (1.4) (2.8) 
 
 Unrealized losses on derivative contracts related to forecasted sales 24.5 23.7 325.5 25.6 
 Unrealized losses on foreign currency option contracts 6.3 1.2 3.0 8.8 
 Take-or-pay contract-based intangible recognition 
 (0.7) (1.1) (1.4) (2.2) 
 Income tax provision (benefit) 11.3 (4.8) 10.3 (6.6) 
 Total Adjusted EBITDA 
 $ 577.8 $ 122.1 $ 905.3 $ 183.2 

 
 
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 Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its segments’ operating performance, as displayed in the reconciliations below. 
 
 Three Months Ended June 30, Six Months Ended June 30, 
 2022 2021 2022 2021 
 (Dollars in millions) 
 Operating costs and expenses 
 $ 825.6 $ 611.4 $ 1,524.6 $ 1,194.0 
 Unrealized losses on foreign currency option contracts (6.3) (1.2) (3.0) (8.8) 
 Take-or-pay contract-based intangible recognition 
 0.7 1.1 1.4 2.2 
 
 Net periodic benefit credit, excluding service cost (12.3) (8.7) (24.5) (17.4) 
 Total Reporting Segment Costs 
 $ 807.7 $ 602.6 $ 1,498.5 $ 1,170.0 

 The following table presents Total Reporting Segment Costs by reporting segment: 
 
 Three Months Ended June 30, Six Months Ended June 30, 
 2022 2021 2022 2021 
 (Dollars in millions) 
 Seaborne Thermal Mining $ 178.1 $ 122.7 $ 338.8 $ 270.6 
 Seaborne Metallurgical Mining 234.1 147.4 374.4 257.3 
 Powder River Basin Mining 231.7 203.1 475.3 401.4 
 Other U.S. Thermal Mining 163.0 117.8 316.1 230.9 
 Corporate and Other 0.8 11.6 (6.1) 9.8 
 Total Reporting Segment Costs $ 807.7 $ 602.6 $ 1,498.5 $ 1,170.0 

 Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton. 
 The following tables present tons sold, revenue, Reporting Segment Costs and Adjusted EBITDA by mining segment: 
 
 Three Months Ended June 30, 2022 
 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining 
 (Amounts in millions, except per ton data) 
 Tons sold 4.0 1.6 18.5 4.4 
 
 Revenue $ 354.9 $ 533.8 $ 229.7 $ 224.9 
 Reporting Segment Costs 178.1 234.1 231.7 163.0 
 Adjusted EBITDA $ 176.8 $ 299.7 $ (2.0) $ 61.9 
 
 Revenue per Ton $ 87.37 $ 330.56 $ 12.44 $ 51.40 
 Costs per Ton 43.85 144.91 12.55 37.25 
 Adjusted EBITDA Margin per Ton $ 43.52 $ 185.65 $ (0.11) $ 14.15 

 
 
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 Three Months Ended June 30, 2021 
 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining 
 (Amounts in millions, except per ton data) 
 Tons sold 4.1 1.4 22.5 3.9 
 
 Revenue $ 194.1 $ 121.0 $ 248.6 $ 162.1 
 Reporting Segment Costs 122.7 147.4 203.1 117.8 
 Adjusted EBITDA $ 71.4 $ (26.4) $ 45.5 $ 44.3 
 
 Revenue per Ton $ 46.92 $ 85.48 $ 11.06 $ 40.70 
 Costs per Ton 29.61 104.24 9.04 29.57 
 Adjusted EBITDA Margin per Ton $ 17.31 $ (18.76) $ 2.02 $ 11.13 

 
 Six Months Ended June 30, 2022 
 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining 
 (Amounts in millions, except per ton data) 
 Tons sold 7.8 2.8 39.1 8.6 
 
 Revenue $ 606.1 $ 855.1 $ 480.9 $ 428.0 
 Reporting Segment Costs 338.8 374.4 475.3 316.1 
 Adjusted EBITDA $ 267.3 $ 480.7 $ 5.6 $ 111.9 
 
 Revenue per Ton $ 77.52 $ 299.82 $ 12.30 $ 49.96 
 Costs per Ton 43.33 131.26 12.16 36.90 
 Adjusted EBITDA Margin per Ton $ 34.19 $ 168.56 $ 0.14 $ 13.06 

 
 Six Months Ended June 30, 2021 
 Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining 
 (Amounts in millions, except per ton data) 
 Tons sold 8.2 2.4 43.2 7.8 
 
 Revenue $ 370.5 $ 208.5 $ 477.0 $ 311.4 
 Reporting Segment Costs 270.6 257.3 401.4 230.9 
 Adjusted EBITDA $ 99.9 $ (48.8) $ 75.6 $ 80.5 
 
 Revenue per Ton $ 45.15 $ 86.31 $ 11.04 $ 39.75 
 Costs per Ton 32.97 106.51 9.29 29.47 
 Adjusted EBITDA Margin per Ton $ 12.18 $ (20.20) $ 1.75 $ 10.28 

 
 
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 Free Cash Flow is defined as net cash provided by (used in) operating activities plus net cash provided by (used in) investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP. 
 
 Six Months Ended June 30, 
 2022 2021 
 (Dollars in millions) 
 Net cash provided by (used in) operating activities $ 9.4 $ (22.8) 
 Net cash provided by (used in) investing activities 94.5 (82.6) 
 
 Free Cash Flow $ 103.9 $ (105.4) 

 
 Regulatory Update 
 Other than as described in the following section, there were no significant changes to the Company’s regulatory matters subsequent to December 31, 2021. Information regarding the Company’s regulatory matters is outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2021. 
 Regulatory Matters - U.S. 
 EPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired EGUs . On October 23, 2015, the United States Environmental Protection Agency (EPA) published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired electric generation units (EGUs) under Section 111(d) of the Clean Air Act (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 (GHGs) from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline). 
 The EPA subsequently proposed to repeal the CPP and in August 2018 issued a proposed rule to replace the CPP with the Affordable Clean Energy (ACE) Rule. In June 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. The ACE rule set emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction (BSER). Numerous petitions for review challenging the ACE Rule were filed in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) and subsequently consolidated. In January 2021, a 3-judge panel of the D.C. Circuit vacated and remanded the ACE Rule to the EPA, including its repeal of the CPP and amendments to the implementing regulations that extended the compliance timeline. 
 On October 29, 2021, the Supreme Court of the United States (Supreme Court) granted certiorari in four consolidated matters seeking review of the D.C. Circuit’s opinion vacating the ACE rule and invalidating the repeal of the CPP. On June 30, 2022, the Supreme Court issued its opinion in West Virginia v. EPA , No. 20-1530 ( West Virginia ). The Supreme Court ruled that the EPA does not have Congressional authority under section 111(d) of the CAA to limit emissions at existing power plants through generation shifting to other fuels and/or renewable energy, but still can regulate emissions at plants by emissions reductions technologies as the EPA has done in the past. The D.C. Circuit’s opinion was reversed and remanded, leaving neither the CPP or the ACE Rule in effect. Thus, it will be necessary for the EPA to initiate new rulemaking in order to control GHGs from EGUs using section 111(d) of the CAA. The EPA tentatively plans to propose emission guidelines for EGUs in the spring of 2023. The Company will continue to monitor EPA rulemaking in this regard. 
 National Ambient Air Quality Standards (NAAQS) . The CAA requires the EPA to review national ambient air quality standards every five years to determine whether revision to current standards are appropriate. As part of this recurring review process, the EPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect. Fifteen states and other petitioners have filed a petition for review of the rule in the D.C. Circuit. The litigation is currently in abeyance following a motion filed by the EPA to allow for review of the standards. 
 The EPA also proposed in 2020 to retain the particulate matter (PM) standards last revised in 2012. On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM 2.5 ) and the primary 24-hour standard for coarse particulate matter (PM 10 ) and secondary PM 10 standards. This rule has also been challenged in the D.C. Circuit by several states and environmental organizations. The case is currently in abeyance following a motion filed by the EPA to allow for review of the standards. 
 
 
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 More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to other NAAQS for nitrogen dioxide (NO 2 ) and sulfur dioxide (SO 2 ), although these standards are not subject to a statutorily-required review until 2023 for NO 2 and 2024 for SO 2 . 
 Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule . In 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in nitrogen oxides (NO x ) beginning in 2017 in 22 states subject to CSAPR. This rule was subsequently remanded back to the EPA. Wisconsin v. EPA , 938 F.3d 303. 
 In April 2021, the EPA published a final rule in the Federal Register to address the D.C. Circuit remand. This rule imposed further reductions of NO x emissions in 12 states that were subject to the original 2016 rule, which was based on the 2008 ozone NAAQS. 
 In the same rule, the EPA determined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. The EPA subsequently issued Federal Implementation Plans (FIPs) to lower state ozone season NO x budgets in 2021 to 2024 in the affected states. A petition for review challenging the 2021 rule was filed in the D.C. Circuit. Briefing is completed and oral arguments have been scheduled for September 28, 2022, but this does not stay the effectiveness of the rule. 
 On April 6, 2022, the EPA proposed FIPs to address regional ozone transport for the 2015 ozone NAAQS. The proposed rule would result in new ozone season emission budgets for NO x in 25 states, including four Western states, and the proposed rule additionally contains provisions that would require daily “backstop” emission limits for coal-fired power plants over 100 megawatts. The proposed rule would also set first-time limits on certain industrial sources. The EPA estimates that by 2026 the compliance cost will be $1.1 billion. These emission limitations would apply in addition to requirements contained in State Implementation Plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations. 
 Mercury and Air Toxic Standards (MATS) . The EPA published the final MATS rule in the Federal Register in 2012. The MATS rule revised the new source performance standards (NSPS) for NO x , SO 2 and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. 
 In 2020, the EPA issued a final rule reversing a prior finding and determined that it is not “appropriate and necessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants. This rule also finalized residual risk and technology review standards for the coal- and oil-fired electricity utility generating units source category. Both actions were challenged in the D.C. Circuit but this litigation was placed in abeyance. On February 9, 2022 the EPA proposed a rule to revoke the 2020 finding and to reaffirm the agency’s 2016 finding that it remains “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants under Clean Air Act section 112. In the same proposal, the EPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency’s review of related residual risk and technology review standards. 
 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. 
 
 
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 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. The EPA issued a final rule in 2020 that could limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances. That rule was temporarily vacated by a district court, but a Supreme Court order on April 7, 2022, effectively reinstated the rule. The EPA issued another proposal in June 2022 that would supersede the 2020 rule and expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. 
 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. Peabody must provide information to agencies when it proposes 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 (CEQ) issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. That final rule sought 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. On April 20, 2022, however, the CEQ published the final Phase 1 rule that partially amended the 2020 rule by restoring key provisions of the pre-2020 NEPA regulations. The CEQ plans to propose a Phase 2 rule in August 2022 that makes broader changes to the 2020 rule. 
 Regulatory Matters - Australia 
 Australia’s federal election on May 21, 2022 resulted in the Labor Party replacing the former Coalition administration. The new Labor government plans several reforms to federal environmental and industrial relations laws that have the potential to negatively impact Australian mining operations; however, the majority of reforms are unlikely to be legislated until 2023. Proposed labor market reforms include legislation that would require contracted or labor hire workers undertaking the same roles as direct employees to be paid equal wages; reduced flexibility of employment; and changes to enterprise bargaining legislation that may increase the difficulty of reaching enterprise agreements. 
 The new Australian federal government has announced plans to legislate for a 43% reduction in Australia’s greenhouse gas emissions by 2030 and to introduce changes by mid-2023 that will require heavy emitting companies producing more than 100,000 tonnes of carbon emissions annually to accelerate their emissions reduction activities. The Australian federal government has also committed to provide an official response to an independent review of Australia’s overarching environmental law, the Environment Protection and Biodiversity Conservation (EPBC) Act, by the end of 2022, with the aim of developing strengthened environmental legislation in 2023. 
 On March 15, 2022, the Full Court of the Federal Court of Australia overturned the decision in Sharma v Minister for the Environment [2021] FCA 560 (Sharma), a case which found in 2021 that the Federal Minister for the Environment had a duty to avoid causing personal injury or death to children in Australia as a result of carbon emissions when deciding an application to approve a coal mine expansion. In light of this decision, the Minister no longer must consider the effects of carbon emissions when assessing referrals under the Environment Protection and Biodiversity Conservation Act 1999. However, an application by Sharma for special leave to appeal to the High Court of Australia remains probable, and the duty could be reinstated. 
 On and from July 1, 2022, the Queensland Government introduced three new royalty tiers for coal produced and sold from the state. The new tier rates are 20% for the portion of prices above $175 Australian dollars per tonne; 30% for prices above $225 Australian dollars per tonne; and a 40% tier for when prices exceed $300 Australian dollars per tonne. Previously, the maximum royalty rate was 15% of the value of the coal sold above $150 Australian dollars per tonne. The change follows a three-year freeze on royalty rates for coal in the state. The Company is working with other coal producers to consider challenges to the implementation of the new royalty tiers. 
 
 
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 Risks Related to Global Climate Change 
 Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to greenhouse gas (GHG) emissions. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2). 
 Peabody’s board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal. 
 The board of directors has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the board. In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the board of directors and Peabody’s global workforce turns those objectives into meaningful actions. 
 Management believes that the Company’s external communications, including environmental regulatory filings and public notices, SEC filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress. All such communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team. 
 The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements. 
 The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies. The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors: 
 • Reduced utilization or closure of existing coal-fired electricity generating plants; 
 • Electricity generators switching from coal to alternative fuels, when feasible; 
 • Increased costs associated with regulatory compliance; 
 • Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations; 
 • Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes; 
 • Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions; 
 • Disruption to operations or markets due to anti-coal activism and litigation; and 
 • Reputational damage associated with involvement in GHG emissions. 
 With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks: 
 • Disruption to water supplies vital to mining operations; 
 • Disruption to transportation and other supply chain activities; 
 • Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and 
 • Electrical grid failures and power outages. 
 
 
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 While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as: 
 • Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and carbon capture, use and storage (CCUS) technologies; 
 • Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and 
 • The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations. 
 Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described within Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021. 
 The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy. 
 From time to time, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows. 
 On March 21, 2022, the SEC proposed rules that would require public companies to disclose extensive climate-related information in certain SEC filings. Specifically, the proposed rules would add new Subpart 1500 to Regulation S-K and new Article 14 to Regulation S-X to require disclosure of climate-related risks that are reasonably likely to have a material impact on a public company’s business, results of operations, or financial condition; GHG emissions associated with a public company that includes, in many cases, an attestation report by a GHG emissions attestation provider; and climate-related financial metrics to be included in a company’s audited financial statements. The Company is currently assessing the potential impact of the proposed rules. 
 
 Liquidity and Capital Resources 
 Overview 
 The Company’s primary source of cash is proceeds from the sale of its coal production to customers. The Company has also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, and selling and administrative expenses. The Company has also used cash for early debt retirements, dividends, and share repurchases 
 
 
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 Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including the restrictions set forth under the Company’s debt and surety agreements, its net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. The Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to its industry, many of which are beyond the Company’s control. The Company has presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds.” 
 Liquidity 
 As of June 30, 2022, the Company’s cash balances totaled $1,120.7 million, including approximately $386 million held by U.S. subsidiaries, $701 million held by Australian subsidiaries, and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. The Australian subsidiaries that conduct the operations of the Wilpinjong Mine held cash of approximately $202 million at June 30, 2022. A significant majority of the cash held by the Company’s foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. From time to time, the Company may repatriate excess cash from its foreign subsidiaries to the U.S. During the first half of 2022, the Company repatriated approximately $200 million. If additional foreign-held cash is repatriated in the future, the Company does not expect restrictions or potential taxes will have a material effect to its near-term liquidity. 
 The Company’s available liquidity increased from $995.9 million as of December 31, 2021 to $1,134.2 million as of June 30, 2022. Available liquidity was comprised of the following: 
 
 June 30, 2022 December 31, 2021 
 (Dollars in millions) 
 Cash and cash equivalents $ 1,120.7 $ 954.3 
 Credit facility availability — 15.3 
 Accounts receivable securitization program availability 13.5 26.3 
 Total liquidity $ 1,134.2 $ 995.9 

 During the three months ended June 30, 2022, the Company executed an amendment to its credit facility to reduce its capacity by approximately $17 million and to make allowable certain previously restricted payments for joint venture investments. The amendment creates an investment basket which allows payments of $30.0 million per year specifically limited to investment in renewable energy-related projects. Unused portions of the basket carryover from year-to-year, and the total amount of investment will further reduce the credit facility capacity by a like amount, or a minimum of $10.0 million per year, through the maturity of the credit facility. The Company expects to utilize its collateralized letter of credit agreement, described below, to offset future required credit facility capacity reductions. The Company has no contractual commitment for renewable energy-related project investment. 
 Margin Requirements 
 From time to time, the Company enters into hedging arrangements, including economic hedging arrangements, to manage various risks, including coal price volatility. Most hedging arrangements require the Company to post margin with its clearing broker based on the value of the related instruments and other credit factors. If the fair value of its exchange-cleared hedge portfolio moves significantly, the Company could be required to post additional margin, which could negatively impact its liquidity. 
 At March 4, 2022, the Company held coal derivative contracts in aggregate of 2.3 million metric tons. The majority of these contracts were entered into in the first half of 2021 and related to 1.9 million metric tons of production at the Wambo Underground Mine in the Company’s Seaborne Thermal Mining segment, which were expected to be mined and settled at a rate of 1.2 million metric tons in 2022 (with 0.4 million metric tons settling in the first half of 2022 and 0.8 million settling in the second half of 2022) and 0.7 million metric tons in 2023. These hedge contracts were put in place to support the profitability of the mine, securing anticipated average prices of $84 per metric ton through mid-2023. The remaining hedges relate to brokered coal transactions and other blending and optimization activities, which will settle throughout 2022. 
 
 
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 High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices, which has been amplified by the Russian-Ukrainian conflict resulting in unprecedented upward volatility in Newcastle coal pricing since late February. The Newcastle financial price for March closed at $419.50 per metric ton on March 4, 2022, which was 148% above the closing index price of $169.17 per metric ton on December 31, 2021. As a result, the Company’s total initial and variation margin requirements reached approximately $750 million during March 2022, and were $544.2 million at June 30, 2022. Margin is returned to the Company upon reductions in the underlying market coal price or, absent such reductions, cash is recovered as the Company delivers coal into the market at spot prices. 
 On March 7, 2022, the Company entered into a credit agreement, by and among the Company, as borrower, Goldman Sachs Lending Partners LLC, as administrative agent, and the lenders party thereto (the Credit Agreement). The Credit Agreement provides for a $150 million unsecured revolving credit facility (the Revolving Facility), which will mature on April 1, 2025 and bears interest at a rate of 10.0% per annum on drawn amounts. The Revolving Facility is intended to support the Company’s near-term liquidity requirements, particularly with respect to the cash margin requirements associated with the Company’s coal derivative contracts. 
 Concurrently with the Credit Agreement, the Company entered into an agreement with Goldman Sachs & Company LLC to act as sales agent for at-the-market equity offerings of up to $225.0 million of the Company’s common stock. 
 During the three months ended March 31, 2022, the Company borrowed and repaid $225.0 million under the Revolving Facility using net proceeds of $222.0 million from at-the-market issuances of 10.1 million shares of common stock and available cash. The Company had no outstanding borrowings and no availability under the Revolving Facility at June 30, 2022. The Company issued a notice to terminate the facility on August 1, 2022 with an effective date of August 4, 2022. 
 To reduce exposure to additional margin requirements, during the six months ended June 30, 2022, the Company converted 0.8 million metric tons of financial hedges into fixed price physical sales over the next 12 months. As of June 30, 2022, 0.9 million metric tons remain outstanding with 0.4 million metric tons projected to settle over the remainder of 2022. On July 29, 2022, the Company had $529.2 million of margin posted. For additional information regarding the Company’s coal derivative contracts, refer to Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Quarterly Report. 
 Collateral Requirements 
 In November 2020, the Company entered into an agreement with the providers of its surety bond portfolio to resolve previous collateral demands. In accordance with the agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit. The Company subsequently granted second liens on $200.0 million of certain mining equipment and is further required to post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the surety providers. The collateral postings further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the surety agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Based upon the Company’s free cash flow through June 30, 2022, additional collateral of $13.0 million was posted during the three months ended March 31, 2022 and $25.7 million was posted subsequent to June 30, 2022, in the form of cash-collateralized letters of credit. The Company is unable to accurately estimate future additional collateral postings due to the sensitivity of free cash flow to external market factors such as coal pricing. 
 Collateralized Letter of Credit Agreement 
 In February 2022, the Company entered into a new agreement, which provides up to $250.0 million of capacity for irrevocable standby letters of credit, expected to primarily support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a deposit rate of 0.35% per annum on the amount of cash collateral posted in support of letters of credit, with the rate subject to variation over time. The agreement has an initial expiration date of December 31, 2025. At June 30, 2022, collateralized letters of credit of $12.3 million were outstanding under the agreement. 
 
 
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 Indebtedness 
 The Company’s total indebtedness as of June 30, 2022 and December 31, 2021 is presented in the table below. 
 
 Debt Instrument (defined below, as applicable) June 30, 2022 December 31, 2021 
 (Dollars in millions) 
 6.000% Senior Secured Notes due March 2022 (2022 Notes) 
 $ — $ 23.1 
 8.500% Senior Secured Notes due December 2024 (2024 Peabody Notes) 
 — 62.6 
 10.000% Senior Secured Notes due December 2024 (2024 Co-Issuer Notes) 
 193.6 193.9 
 Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) 138.8 206.0 
 6.375% Senior Secured Notes due March 2025 (2025 Notes) 
 77.5 334.9 
 Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) 320.9 322.8 
 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) 320.0 — 
 
 
 Finance lease obligations 24.1 29.3 
 Less: Debt issuance costs (28.0) (34.8) 
 1,046.9 1,137.8 
 Less: Current portion of long-term debt 177.7 59.6 
 Long-term debt $ 869.2 $ 1,078.2 

 The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at June 30, 2022, of approximately $40 million during the six months ending December 31, 2022, and approximately $70 million in 2023, $400 million in 2024, $405 million in 2025, and $355 million thereafter. However, as further described below, certain pending transactions to repurchase debt principal could alter the timing and amount of principal and interest payments. 
 Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $40.6 million and $48.0 million during the three months ended June 30, 2022 and 2021, respectively, and $77.8 million and $104.3 million during the six months ended June 30, 2022 and 2021, respectively. 
 2021 Financing Activity and Subsequent Repurchases 
 During the first quarter of 2021, the Company completed a series of transactions to provide the Company with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity. These transactions included a senior notes exchange, a revolving credit facility exchange, various amendments to the Company’s existing debt agreements, and a support agreement with the Company’s surety bond providers. 
 Subsequent to these transactions, the Company completed additional financing transactions which included the implementation of an at-the-market equity offering program pursuant to which the Company sold approximately 24.8 million shares of common stock for net cash proceeds of $269.8 million, the retirement of $270.9 million principal amount of existing debt through various open market purchases at an aggregate cost of $232.4 million, and the issuance of an aggregate 10.0 million shares of common stock in exchange for an additional $106.1 million principal amount of existing debt through multiple bilateral transactions with debt holders. 
 In the event of open market purchases of its debt, the terms of the 2024 Peabody Notes - now redeemed as described below - required, and the letter of credit facility entered into by the Company in connection with the 2021 financing activity (Company LC Agreement) requires the Company to make repurchase offers to those debt and lien holders. In general, the repurchase offers equate to 25% of the principal amount of priority lien debt repurchased in the preceding quarter at a price equal to the weighted average repurchase price paid over that quarter. The open market debt repurchases completed during the three months ended December 31, 2021 necessitated a mandatory repurchase offer of up to $38.6 million of 2024 Peabody Notes, at 94.940% of their aggregate accreted value, plus accrued and unpaid interest, and a concurrent repurchase offer of priority lien obligations under the Company LC Agreement. The offer resulted in the valid tender and purchase of $0.1 million aggregate accreted value of 2024 Peabody Notes and $30.0 million aggregate principal and commitment amounts under the Company LC Agreement during the three months ended March 31, 2022. The Company’s purchase of the principal and commitment amounts under the Company LC Agreement was effected by the posting of $28.5 million of collateral with the administrative agent and did not reduce the availability under the facility. 
 
 
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 The 2024 Co-Issuer Notes and the Co-Issuer Term Loans are also subject to mandatory prepayment offers at the end of each six-month period, beginning with June 30, 2021, whereby the Excess Cash Flow (as defined in the 2024 Co-Issuer Notes indenture) generated by the Wilpinjong Mine during each such period will be applied to the principal of such notes and loans on a pro rata basis, provided that the liquidity attributable to the Wilpinjong Mine would not fall below $60.0 million. Such prepayments may be accepted or declined at the option of the debt holders. Based upon the Wilpinjong Mine’s results for the six-month period ended December 31, 2021, a required offer to prepay $105.6 million of total principal resulted in the prepayment of $17.2 million of Co-Issuer Term Loans principal, $0.3 million of 2024 Co-Issuer Notes principal, and a related loss on early debt extinguishment of $0.5 million during the three months ended March 31, 2022. Based upon the Wilpinjong Mine’s results for the six-month period ended June 30, 2022, the Company was required to offer to prepay $65.1 million of total principal subsequent to June 30, 2022. The holders of the Co-Issuer Term Loans unanimously declined their $37.9 million pro rata portion of the offer and the $27.2 million pro rata portion of the offer to the holders of the 2024 Co-Issuer Notes will expire on August 29, 2022. 
 Voluntary repurchases of Co-Issuer Term Loans are permissible through a modified Dutch auction process. During the three months ended June 30, 2022, the Company solicited bids under such process from all holders of Co-Issuer Term Loans for the repurchase of up to $50.0 million principal amount at prices acceptable to the Company. The auction process resulted in the repurchase of $50.0 million principal amount at a weighted average price of 103.91%, or $52.0 million. 
 Additionally, the indenture which governs the 2024 Co-Issuer Notes requires that, within 30 business days following a repurchase of the Co-Issuer Term Loans such as that undertaken through the auction process described above, the Company must also offer to repurchase an equivalent principal amount of the 2024 Co-Issuer Notes at the equivalent purchase price. As such, the required offer for $50.0 million aggregate principal amount was made by the Company on May 26, 2022 and subsequently increased to $93.9 million, at the Company’s discretion, subsequent to June 30, 2022. Prior to expiration of the offer, an excess aggregate principal amount of 2024 Co-Issuer Notes had been validly tendered, but the terms of the offer limited the repurchase to $93.9 million. The Company completed the repurchase on July 25, 2022 for $97.5 million. 
 The credit agreement which governs the Co-Issuer Term Loans requires parity between the holders of Co-Issuer Term Loans and holders of the 2024 Co-Issuer Notes with respect to repurchase offers. Accordingly, the discretionary increase to the 2024 Co-Issuer Notes repurchase offer compelled the Company to offer to repurchase an additional $43.9 million of aggregate principal amount of Co-Issuer Term Loans at 103.91% subsequent to June 30, 2022. The offer will expire on August 22, 2022. 
 Prior to June 30, 2022, the Company reached agreements to repurchase $22.6 million aggregate principal amount of its Senior Secured Term Loan for $21.3 million in open market transactions. The repurchases settled subsequent to June 30, 2022. As a result of these repurchases, the Company will offer to repurchase $5.7 million of priority lien obligations under the Company LC Agreement at approximately 94% during the three months ending December 31, 2022. 
 Retirement of 2022 Notes 
 On March 31, 2022, the Company retired the remaining principal balance of 2022 Notes upon maturity for $23.1 million. 
 3.250% Convertible Senior Notes due 2028 
 On March 1, 2022, through a private offering, the Company issued $320.0 million in aggregate principal amount of 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes). The 2028 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture. 
 The Company used the proceeds of the offering of the 2028 Convertible Notes to redeem the remaining $62.6 million of its outstanding 2024 Peabody Notes and, together with available cash, approximately $257.4 million of its outstanding 2025 Notes, and to pay related premiums, fees and expenses relating to the offering of the 2028 Convertible Notes and the redemptions. The Company capitalized $11.2 million of debt issuance costs related to the offering and recognized a loss on early debt extinguishment of $23.0 million during the three months ended March 31, 2022. 
 The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes will bear interest from March 1, 2022 at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year, beginning on September 1, 2022. 
 
 
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 The 2028 Convertible Notes will be convertible at the option of the holders only in the following circumstances: (1) during any calendar quarter commencing after the calendar quarter ended on June 30, 2022, if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price for each of at least 20 trading days during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter; (2) during the five consecutive business days immediately after any five consecutive trading day period (such five consecutive trading day period, the Measurement Period) in which the trading price per $1,000 principal amount of 2028 Convertible Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of the Company’s common stock on such trading day and the conversion rate on such trading day; (3) upon the occurrence of certain corporate events or distributions on the Company’s common stock; (4) if the Company calls any 2028 Convertible Notes for redemption; and (5) at any time from, and including, September 1, 2027 until the close of business on the second scheduled trading day immediately before the maturity date. 
 Upon conversion, the Company may satisfy its conversion obligation by paying or delivering, as applicable, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture. The initial conversion rate for the 2028 Convertible Notes will be 50.3816 shares of the Company’s common stock per $1,000 principal amount of 2028 Convertible Notes, which represents an initial conversion price of approximately $19.85 per share of the Company’s common stock. The initial conversion price represents a premium of approximately 32.5% to the $14.98 per share closing price of the Company’s common stock on February 24, 2022. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture. If certain corporate events described in the indenture occur prior to the maturity date, or the Company delivers a notice of redemption (as described below), the conversion rate will be increased for a holder who elects to convert its 2028 Convertible Notes in connection with such corporate event or notice of redemption, as the case may be, in certain circumstances. 
 The Company may not redeem the 2028 Convertible Notes prior to March 1, 2025. The Company may redeem for cash all or any portion of the 2028 Convertible Notes, at its option, on or after March 1, 2025 and on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to 100% of the principal amount of the 2028 Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price on (1) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice; and (2) the trading day immediately before the date the Company sends such notice. However, the Company may not redeem less than all of the outstanding 2028 Convertible Notes unless at least $75 million aggregate principal amount of 2028 Convertible Notes are outstanding and not called for redemption as of the time the Company sends the related redemption notice. No sinking fund is provided for the 2028 Convertible Notes. 
 If the Company undergoes a fundamental change (as defined in the indenture), noteholders may require the Company to repurchase their 2028 Convertible Notes at a cash repurchase price equal to 100% of the principal amount of the 2028 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. 
 Covenant Compliance 
 The Company was compliant with all relevant covenants under its debt agreements at June 30, 2022, including the minimum aggregate liquidity requirement under the Company LC Agreement which requires the Company’s restricted subsidiaries to maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024. The Company’s restricted subsidiaries’ relevant liquidity amounted to $930.7 million at June 30, 2022. 
 Accounts Receivable Securitization Program 
 As described in Note 12. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017. The securitization program was amended in January 2022 to extend its maturity to January 2025 and reduce the available funding capacity from $250.0 million to $175.0 million, which better aligns with the current average borrowing base. Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing. Funding capacity under the program may also be utilized for letters of credit in support of other obligations. At June 30, 2022, the Company had no outstanding borrowings and $161.5 million of letters of credit outstanding under the program, which were primarily in support of portions of the Company’s reclamation obligations. The Company was not required to post cash collateral under the securitization program at June 30, 2022. 
 
 
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 Cash Flows and Free Cash Flow 
 The following table summarizes the Company’s cash flows for the six months ended June 30, 2022 and 2021, as reported in the accompanying unaudited condensed consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP. 
 
 Six Months Ended June 30, 
 2022 2021 
 (Dollars in millions) 
 Net cash provided by (used in) operating activities $ 9.4 $ (22.8) 
 Net cash provided by (used in) investing activities 94.5 (82.6) 
 Net cash provided by (used in) financing activities 75.1 (41.9) 
 Net change in cash, cash equivalents and restricted cash 179.0 (147.3) 
 Cash, cash equivalents and restricted cash at beginning of period 954.3 709.2 
 Cash, cash equivalents and restricted cash at end of period $ 1,133.3 $ 561.9 
 
 Net cash provided by (used in) operating activities $ 9.4 $ (22.8) 
 Net cash provided by (used in) investing activities 94.5 (82.6) 
 
 Free Cash Flow $ 103.9 $ (105.4) 

 Operating Activities. The increase in net cash provided by operating activities for the six months ended June 30, 2022 compared to the same period in the prior year was driven by a year-over-year increase in operating cash flow, primarily from Company’s mining operations ($446.3 million), partially offset by cash utilized to satisfy the margin requirements associated with derivative financial instruments ($414.1 million). 
 Investing Activities. The increase in net cash provided by investing activities for the six months ended June 30, 2022 compared to the same period in the prior year was driven by higher cash receipts from Middlemount ($140.9 million) and lower capital expenditures and payments of capital accruals ($25.2 million). 
 Financing Activities. The increase in net cash provided by financing activities for the six months ended June 30, 2022 compared to the same period in the prior year was driven by higher cash proceeds from long-term debt and common stock issuances ($545.0 million and $156.9 million, respectively), partially offset by higher repayments of debt principal ($571.7 million) and higher distributions to non-controlling interests ($13.7 million). 
 
 Off-Balance-Sheet Arrangements 
 In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At June 30, 2022, such instruments inc lude d $1,453.5 million of surety bonds and $475.1 million o f letters of credit. Such financial instruments provide support for its reclamation bonding requirements, lease obligations, insu rance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in its condensed consolidated balance sheets. 
 
 
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 As of June 30, 2022, 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 $ 1,276.9 $ 40.5 $ 84.2 $ 35.0 $ 16.9 $ 1,453.5 
 Letters of credit outstanding under letter of credit facilities 212.5 89.3 6.8 5.0 — 313.6 
 Letters of credit outstanding under accounts receivable securitization program 133.9 17.6 10.0 — — 161.5 
 
 1,623.3 147.4 101.0 40.0 16.9 1,928.6 
 Less: Letters of credit in support of surety bonds (4) 
 (339.5) (30.3) (2.3) (1.2) — (373.3) 
 Less: Cash collateral in support of surety bonds (4) 
 (15.0) — — — — (15.0) 
 
 Obligations supported, net $ 1,268.8 $ 117.1 $ 98.7 $ 38.8 $ 16.9 $ 1,540.3 

 (1) Obligations include pension and health care plans, workers’ compensation, and property and casualty insurance 
 (2) Obligations pertain to customer and vendor contracts 
 (3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration 
 (4) Serve as collateral for certain surety bonds at the request of surety bond providers. The Company has also posted $9.1 million in incremental cash collateral directly with the beneficiary that is not supported by a surety bond. 
 Financial assurances associated with new reclamation bonding requirements, surety bonds or other obligations may require additional collateral in the form of cash or letters of credit causing a decline in the Company’s liquidity. 
 As described in Note 12. “Financial Instruments and Other Guarantees” in the accompanying unaudited condensed consolidated financial statements, the Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. Self-bonding in the U.S. has become increasingly restricted in recent years, leading to the Company’s increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on its liquidity due to increased collateral requirements and surety and related fees. 
 At June 30, 2022, the Company had total asset retirement obligations of $725.1 million which were backed by a combination of surety bonds, bank guarantees and letters of credit. 
 Bonding requirement amounts may differ significantly from the re lated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date. 
 
 Critical Accounting Policies and Estimates 
 The Company’s discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its financial statements, which have been prepared in accordance with U.S. GAAP. The Company is also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, the Company evaluates its estimates. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. 
 
 
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 The Company’s critical accounting policies and estimates are discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2021. The Company’s critical accounting policies remain unchanged at June 30, 2022, and there have been no material changes in the Company’s critical accounting estimates. 
 
 Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented 
 See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to the Company’s unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.
PEABODY ENERGY CORP 10-Q

Item 2. Management’s Discussion and Analysis
