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美國
證券交易委員會
華盛頓特區20549
表格 10-Q

（標記一）
☑根據第13或15(d)條規定的季度報告
證券交易所法案(1934年)
截至季度結束
2024年9月30日

or
☐根據第13條或第15條(d)的規定進行過渡報告
證券交易所法案(1934年)
對於從____________至____________的過渡期
委託文件編號：001-398661-16463
____________________________________________
peabodylogoa36.jpg
peabody energy 協會CORATION
(根據其章程規定的註冊人準確名稱)
特拉華州13-4004153
（設立或組織的其他管轄區域） （納稅人識別號碼）
701 Market Street,聖路易斯密蘇里州63101-1826
，（主要行政辦公地址）(郵政編碼)
(314) 342-3400
(註冊人電話號碼，包括區號)
在法案第12(b)條的規定下注冊的證券：
每一類的名稱交易標誌在其上註冊的交易所的名稱
普通股，每股面值0.01美元英熱單位。請使用moomoo賬號登錄查看New York Stock Exchange
請在以下空格內打勾，以表示註冊人：(1)在過去12個月(或註冊人所要求提交此類報告的更短期間內)已提交了根據1934年證券交易法第13或15(d)條規定需要提交的所有報告；並且(2)在過去90個天內一直遵守此類提交要求。Yes ☑  否 ☐
請使用複選標記指示，註冊人是否在過去12個月（或註冊人必須提交此類文件的較短期間）遞交了根據S-t法規第405條規定需要遞交的每個交互式數據文件。 Yes ☑  否 ☐
請勾選圓圈以表示公司的註冊人是否爲大型加速報告公司、加速報告公司、非加速報告公司、小型報告公司或新興成長公司。有關「大型加速報告公司」、「加速報告公司」、「小型報告公司」和「新興成長公司」的定義，請參見《交易所法規》第120億.2條。
大型加速報告人 ☑                          加速報告人☐
非加速報告人☐                較小的報告公司 ☐
新興增長型公司 ☐
如果是新興成長型企業，請勾選複選標記，表明註冊者已選擇不使用延長過渡期來符合根據證券交易法第13(a)條規定提供的任何新財務會計準則。 ☐
請在以下方框內打勾：公司是否是空殼公司(根據證券交易法第12b-2條規定定義）。是☐ 否 ☑
截至2023年7月31日，續借貸款協議下未償還的借款額爲121.5 註冊人的普通股（每股面值爲0.01美元）於2024年11月4日持有的股份爲百萬股。


目錄
 頁面
 
 

目錄


第一部分 - 財務信息
項目1.基本報表。
皮博迪能源公司
未經審計的基本財務報表綜合損益表

截至9月30日的三個月截至9月30日的九個月內，
2024202320242023
（金額單位：百萬美元，每股數據除外）
營業收入$1,088.0 $1,078.9 $3,113.6 $3,711.7 
費用和支出
淨利潤（不包括下列分項所示的數額）845.8 803.7 2,463.9 2,512.3 
折舊、減值和攤銷84.7 82.3 247.4 239.2 
資產養老責任費用12.9 15.4 38.7 46.3 
銷售及管理費用20.6 21.5 64.7 66.0 
重組費用1.9 0.9 2.1 3.0 
其他營業（收入）損失：
處置淨利得(0.1)(1.4)(9.7)(8.5)
資產減值— — — 2.0 
爲NARm和Shoal Creek損失提供準備金— 3.3 3.7 37.0 
Shoal Creek保險索賠— — (109.5)— 
股權聯營公司損益（收益）2.1 (5.6)7.1 (9.7)
營業利潤120.1 158.8 405.2 824.1 
利息支出，減去資本化利息9.7 13.8 35.1 45.5 
提前償還債務產生的淨損失— — — 8.8 
利息收入(17.7)(20.3)(53.7)(56.5)
除服務成本外的淨週期性福利貸方(10.1)(10.0)(30.4)(29.4)
未來營業收入淨額138.2 175.3 454.2 855.7 
所得稅費用25.7 46.5 85.2 238.7 
扣除所得稅後的持續經營活動收入112.5 128.8 369.0 617.0 
（損失）終止經營業務淨收益（損失），淨收益稅後(1.0)2.5 (3.3)(0.1)
淨利潤111.5 131.3 365.7 616.9 
淨利潤歸屬於非控制權益10.2 11.4 25.4 49.3 
歸屬於普通股股東的淨收益$101.3 $119.9 $340.3 $567.6 
持續經營收入：
每股基本收益$0.82 $0.88 $2.72 $4.06 
每股攤薄收益$0.74 $0.80 $2.47 $3.68 
歸屬於普通股股東的淨利潤：  
每股基本收益$0.81 $0.90 $2.69 $4.05 
每股攤薄收益$0.74 $0.82 $2.44 $3.68 
請參見附註的未經審計的簡明合併財務報表。

1

目錄


皮博迪能源公司
未經審計的簡明綜合收益表

截至9月30日的三個月截至9月30日的九個月內，
2024202320242023
(金額單位：百萬美元)
淨利潤$111.5 $131.3 $365.7 $616.9 
養老金計劃（淨額爲$0.0 每期稅款準備金（稅款淨額在每期）
(13.3)(13.5)(39.8)(40.3)
外幣翻譯調整2.3 (1.0)0.9 (1.6)
其他全部損失，扣除所得稅淨額(11.0)(14.5)(38.9)(41.9)
綜合收益100.5 116.8 326.8 575.0 
淨利潤歸屬於非控制權益10.2 11.4 25.4 49.3 
歸屬於普通股股東的綜合收益$90.3 $105.4 $301.4 $525.7 
請參見附註的未經審計的簡明合併財務報表。

2

目錄


皮博迪能源公司
簡明合併資產負債表
(未經審計)
2024年9月30日2023年12月31日
（金額單位爲以百萬計，每股數據除外）
資產  
流動資產  
現金及現金等價物$772.9 $969.3 
應收賬款，減去2024年4月30日和2024年1月31日的信用損失準備，分別爲 0.0 截至2024年9月30日和2023年12月31日
304.2 389.7 
淨存貨444.3 351.8 
其他資產286.6 308.9 
總流動資產1,808.0 2,019.7 
Property, plant, equipment and mine development, net3,013.5 2,844.1 
經營租賃權使用資產121.1 61.9 
Restricted cash and collateral839.0 957.6 
投資和其他資產85.3 78.8 
資產總額$5,866.9 $5,962.1 
負債和股東權益  
流動負債  
開多次數$14.8 $13.5 
應付賬款和應計費用763.8 965.5 
流動負債合計778.6 979.0 
長期債務，減去當期部分323.7 320.7 
延遲所得稅17.8 28.6 
資產退休義務，減少當前部分647.4 648.6 
退休後福利成本143.1 148.4 
租賃負債，除去當前部分94.6 47.7 
其他非流動負債171.3 181.6 
負債合計2,176.5 2,354.6 
股東權益  
優先股 — $0.01 每股面值； 100.0 no 2024年9月30日和2023年12月31日股份發行或已發行
— — 
普通股系列 — $0.01 每股帳面價值; 50.0 no 2024年9月30日和2023年12月31日股份發行或已發行
— — 
普通股 — $0.01 每股面值； 450.0 189.1股份發行量爲121.4 截至2024年9月30日的流通股份達到 188.6股份發行量爲128.7 2023年12月31日的股份總數
1.9 1.9 
額外實收資本3,988.9 3,983.0 
開多股票，以成本計量 — 67.7 和 59.9 截至2024年9月30日和2023年12月31日的普通股份
(1,926.5)(1,740.2)
保留盈餘1,424.3 1,112.7 
累計其他綜合收益150.7 189.6 
peabody energy公司股東權益3,639.3 3,547.0 
非控制權益51.1 60.5 
股東權益總額3,690.4 3,607.5 
負債和股東權益總額$5,866.9 $5,962.1 
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended September 30,
20242023
 (Dollars in millions)
Cash Flows From Operating Activities 
Net income$365.7 $616.9 
Loss from discontinued operations, net of income taxes3.3 0.1 
Income from continuing operations, net of income taxes369.0 617.0 
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities: 
Depreciation, depletion and amortization247.4 239.2 
Noncash interest expense, net4.0 4.0 
Deferred income taxes(10.9)71.8 
Noncash share-based compensation5.7 5.1 
Asset impairment— 2.0 
Noncash provision for NARM and Shoal Creek losses— 33.7 
Net gain on disposals(9.7)(8.5)
Noncash income from port and rail capacity assignment(0.3)(9.4)
Net loss on early debt extinguishment— 8.8 
Loss (income) from equity affiliates7.1 (9.7)
Shoal Creek insurance recovery (16.6)— 
Foreign currency option contracts(0.4)(0.1)
Changes in current assets and liabilities: 
Accounts receivable82.0 126.6 
Inventories(92.6)(59.9)
Other current assets15.6 30.1 
Accounts payable and accrued expenses(198.3)(29.2)
Collateral arrangements143.3 (145.9)
Asset retirement obligations(1.2)3.9 
Workers’ compensation obligations(2.0)(1.3)
Postretirement benefit obligations(45.0)(46.3)
Pension obligations— 0.9 
Other, net(5.7)(0.1)
Net cash provided by continuing operations491.4 832.7 
Net cash used in discontinued operations(4.7)(79.6)
Net cash provided by operating activities486.7 753.1 



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PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
Nine Months Ended September 30,
20242023
(Dollars in millions)
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development(265.7)(190.4)
Changes in accrued expenses related to capital expenditures(6.5)(5.1)
Wards Well acquisition(143.8)— 
Insurance proceeds attributable to Shoal Creek equipment losses10.9 — 
Proceeds from disposal of assets, net of receivables16.1 13.9 
Contributions to joint ventures(550.1)(573.4)
Distributions from joint ventures549.8 579.4 
Other, net(0.3)1.0 
Net cash used in investing activities(389.6)(174.6)
Cash Flows From Financing Activities
Repayments of long-term debt(7.2)(6.9)
Payment of debt issuance and other deferred financing costs(11.1)(0.3)
Common stock repurchases(183.1)(264.0)
Repurchase of employee common stock relinquished for tax withholding(4.1)(13.7)
Dividends paid(28.5)(20.7)
Distributions to noncontrolling interests(34.8)(58.9)
Net cash used in financing activities(268.8)(364.5)
Net change in cash, cash equivalents and restricted cash(171.7)214.0 
Cash, cash equivalents and restricted cash at beginning of period (1)
1,650.2 1,417.6 
Cash, cash equivalents and restricted cash at end of period (2)
$1,478.5 $1,631.6 
(1) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at beginning of period”:
Cash and cash equivalents$969.3 
Restricted cash included in “Restricted cash and collateral”680.9 
Cash, cash equivalents and restricted cash at beginning of period$1,650.2 
(2) The following table provides a reconciliation of “Cash, cash equivalents and restricted cash at end of period”:
Cash and cash equivalents$772.9 
Restricted cash included in “Restricted cash and collateral”705.6 
Cash, cash equivalents and restricted cash at end of period$1,478.5 
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions, except per share data)
Common Stock
Balance, beginning of period$1.9 $1.9 $1.9 $1.9 
Balance, end of period1.9 1.9 1.9 1.9 
Additional paid-in capital
Balance, beginning of period3,987.2 3,979.4 3,983.0 3,975.9 
Dividend equivalent units on dividends declared0.1 0.1 0.2 0.2 
Share-based compensation for equity-classified awards1.6 1.7 5.7 5.1 
Balance, end of period3,988.9 3,981.2 3,988.9 3,981.2 
Treasury stock
Balance, beginning of period(1,825.5)(1,572.4)(1,740.2)(1,372.9)
Common stock repurchases(100.0)(91.0)(183.1)(264.0)
Net change in unsettled common stock repurchases— 8.6 2.6 (2.6)
Excise tax accrued on common stock repurchases(1.0)(0.9)(1.7)(2.5)
Repurchase of employee common stock relinquished for tax withholding— — (4.1)(13.7)
Balance, end of period(1,926.5)(1,655.7)(1,926.5)(1,655.7)
Retained earnings
Balance, beginning of period1,332.5 820.7 1,112.7 383.9 
Net income attributable to common stockholders101.3 119.9 340.3 567.6 
Dividends declared ($0.075, $0.075, $0.225 and $0.150 per share, respectively)
(9.5)(10.0)(28.7)(20.9)
Balance, end of period1,424.3 930.6 1,424.3 930.6 
Accumulated other comprehensive income
Balance, beginning of period161.7 215.1 189.6 242.5 
Postretirement plans (net of $0.0 tax provisions in each period)
(13.3)(13.5)(39.8)(40.3)
Foreign currency translation adjustment2.3 (1.0)0.9 (1.6)
Balance, end of period150.7 200.6 150.7 200.6 
Noncontrolling interests
Balance, beginning of period57.2 78.6 60.5 63.5 
Net income attributable to noncontrolling interests10.2 11.4 25.4 49.3 
Distributions to noncontrolling interests(16.3)(36.1)(34.8)(58.9)
Balance, end of period51.1 53.9 51.1 53.9 
Total stockholders’ equity$3,690.4 $3,512.5 $3,690.4 $3,512.5 
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1)    Basis of Presentation
The unaudited condensed consolidated financial statements include the accounts of Peabody Energy Corporation (PEC) and its consolidated subsidiaries and affiliates (along with PEC, the Company or Peabody). Interests in subsidiaries controlled by the Company are consolidated with any outside stockholder interests reflected as noncontrolling interests, except when the Company has an undivided interest in a joint venture. In those cases, the Company includes its proportionate share in the assets, liabilities, revenue and expenses of the jointly controlled entities within each applicable line item of the unaudited condensed consolidated financial statements. All intercompany transactions, profits and balances have been eliminated in consolidation.
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements and should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023. In the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation. Balance sheet information presented herein as of December 31, 2023 has been derived from the Company’s audited consolidated balance sheet at that date. The Company’s results of operations for the three and nine months ended September 30, 2024 are not necessarily indicative of the results that may be expected for future quarters or for the year ending December 31, 2024.
(2)    Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
Newly Adopted Accounting Standards
The Company did not adopt any new accounting standards that had a material impact on its unaudited condensed consolidated financial statements or disclosures.
Accounting Standards Not Yet Implemented
Segments. In November 2023, ASU 2023-07 was issued, which requires public entities to provide in interim periods all disclosures about a reportable segment’s profit or loss that are currently required annually; disclose significant expense categories and amounts that are easily computable from the management reports that are regularly provided to the chief operating decision maker (CODM); disclose how the CODM uses each reported measure to allocate resources; and disclose the name and title of the position of the individual identified as the CODM. The Company is required to adopt the amendments for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Company expects this ASU to only impact its disclosures with no impacts to its consolidated results of operations, cash flows and financial condition.
Income Taxes. In December 2023, ASU 2023-09 was issued, which requires public entities to disclose more information primarily related to the income tax rate reconciliation and income taxes paid. The guidance also eliminates certain existing disclosure requirements related to uncertain tax positions and unrecognized deferred tax liabilities. The Company is required to adopt the amendments for fiscal years beginning after December 15, 2024. The amendments should be applied prospectively, with a retrospective option. Early adoption is permitted. The Company expects this ASU to only impact its disclosures with no impacts to its consolidated results of operations, cash flows and financial condition.
(3)    Revenue Recognition
Refer to Note 1. “Summary of Significant Accounting Policies” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, for the Company’s policies regarding “Revenue” and “Accounts receivable, net.”

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Disaggregation of Revenue
Revenue by product type and market is set forth in the following tables. With respect to its seaborne reporting segments, the Company classifies as “Export” certain revenue from domestically-delivered coal under contracts in which the price is derived on a basis similar to export contracts.
Three Months Ended September 30, 2024
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$38.8 $— $304.2 $214.0 $— $557.0 
Export272.4 — — — — 272.4 
Total thermal311.2 — 304.2 214.0 — 829.4 
Metallurgical coal
Export— 240.4 — — — 240.4 
Total metallurgical— 240.4 — — — 240.4 
Other (2)
2.0 2.1 1.1 2.7 10.3 18.2 
Revenue$313.2 $242.5 $305.3 $216.7 $10.3 $1,088.0 
Three Months Ended September 30, 2023
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$31.3 $— $313.3 $227.1 $— $571.7 
Export265.9 — — — — 265.9 
Total thermal297.2 — 313.3 227.1 — 837.6 
Metallurgical coal
Export— 246.0 — — — 246.0 
Total metallurgical— 246.0 — — — 246.0 
Other (2)
0.2 1.0 (0.3)1.1 (6.7)(4.7)
Revenue$297.4 $247.0 $313.0 $228.2 $(6.7)$1,078.9 
Nine Months Ended September 30, 2024
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$116.3 $— $779.7 $592.3 $— $1,488.3 
Export786.1 — — — — 786.1 
Total thermal902.4 — 779.7 592.3 — 2,274.4 
Metallurgical coal
Export— 778.4 — — — 778.4 
Total metallurgical— 778.4 — — — 778.4 
Other (2)
2.2 5.4 1.6 18.0 33.6 60.8 
Revenue$904.6 $783.8 $781.3 $610.3 $33.6 $3,113.6 

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Nine Months Ended September 30, 2023
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
Corporate and Other (1)
Consolidated
(Dollars in millions)
Thermal coal
Domestic$100.7 $— $878.1 $673.2 $— $1,652.0 
Export942.2 — — — — 942.2 
Total thermal1,042.9 — 878.1 673.2 — 2,594.2 
Metallurgical coal
Export— 904.8 — — — 904.8 
Total metallurgical— 904.8 — — — 904.8 
Other (2)
0.5 3.1 (0.1)4.3 204.9 212.7 
Revenue$1,043.4 $907.9 $878.0 $677.5 $204.9 $3,711.7 
(1)    Corporate and Other includes the following:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
(Dollars in millions)
Unrealized gains on derivative contracts related to forecasted sales$— $— $— $159.0 
Realized losses on derivative contracts related to forecasted sales— — — (80.9)
Revenue from physical sale of coal (3)
5.9 (10.4)20.1 97.4 
Trading revenue— (0.1)— — 
Other (2)
4.4 3.8 13.5 29.4 
Total Corporate and Other$10.3 $(6.7)$33.6 $204.9 
(2)    Includes revenue from arrangements such as customer contract-related payments associated with volume shortfalls; royalties related to coal lease agreements; sales agency commissions; farm income; property and facility rentals; and revenue related to the Company’s assignment of rights to its excess port and rail capacity.
(3)    Includes revenue recognized upon the physical sale of coal purchased from the Company’s operating segments and sold to customers through the Company’s coal trading business, including as part of settling certain derivative contracts. Primarily represents the difference between the price contracted with the customer and the price allocated to the operating segment.
Accounts Receivable
“Accounts receivable, net” at September 30, 2024 and December 31, 2023 consisted of the following:
September 30, 2024December 31, 2023
 (Dollars in millions)
Trade receivables, net$245.9 $322.3 
Miscellaneous receivables, net58.3 67.4 
Accounts receivable, net$304.2 $389.7 
None of the above receivables included allowances for credit losses at September 30, 2024 or December 31, 2023. No charges for credit losses were recognized during the three and nine months ended September 30, 2024 or 2023.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(4)     Inventories
“Inventories, net” as of September 30, 2024 and December 31, 2023 consisted of the following:
September 30, 2024December 31, 2023
 (Dollars in millions)
Materials and supplies, net$171.2 $153.0 
Raw coal116.4 105.6 
Saleable coal156.7 93.2 
Inventories, net$444.3 $351.8 
Materials and supplies inventories, net presented above have been shown net of reserves of $5.1 million and $7.2 million as of September 30, 2024 and December 31, 2023, respectively.
(5) Equity Method Investments
The Company’s equity method investments include its interests in Middlemount Coal Pty Ltd (Middlemount), R3 Renewables LLC (R3) and certain other equity method investments.
The table below summarizes the book value of those investments, which are reported in “Investments and other assets” in the condensed consolidated balance sheets, and the related “Loss (income) from equity affiliates”:
Loss (Income) from Equity Affiliates
Book Value atThree Months Ended September 30,Nine Months Ended September 30,
September 30, 2024December 31, 20232024202320242023
(Dollars in millions)
Equity method investment related to Middlemount$47.3 $42.5 $(2.2)$(8.2)$(4.1)$(14.9)
Equity method investment related to R36.6 7.1 4.3 2.6 11.2 5.2 
Total equity method investments$53.9 $49.6 $2.1 $(5.6)$7.1 $(9.7)
R3
The Company contributed $10.8 million and $5.5 million to R3 during the nine months ended September 30, 2024 and 2023, respectively.
(6) Derivatives and Fair Value Measurements
Derivatives
From time to time, the Company may utilize various types of derivative instruments to manage its exposure to risks in the normal course of business, including (1) foreign currency exchange rate risk and the variability of cash flows associated with forecasted Australian dollar expenditures made in its Australian mining platform and (2) price risk of fluctuating coal prices related to forecasted sales or purchases of coal, or changes in the fair value of a fixed price physical sales contract. These risk management activities are actively monitored for compliance with the Company’s risk management policies.
On a limited basis, the Company engages in the direct and brokered trading of coal and freight-related contracts. Except those contracts for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for at fair value.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign Currency
The Company utilizes options and collars to hedge currency risk associated with anticipated Australian dollar operating expenditures. As of September 30, 2024, the Company held average rate options with an aggregate notional amount of $531.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar operating expenditures over the nine-month period ending June 30, 2025. The instruments entitle the Company to receive payment on the notional amount should the quarterly average Australian dollar-to-U.S. dollar exchange rate exceed amounts ranging from $0.70 to $0.74 over the nine-month period ending June 30, 2025. As of September 30, 2024, the Company also held purchased collars with an aggregate notional amount of $468.0 million Australian dollars related to anticipated Australian dollar operating expenditures during the nine-month period ending June 30, 2025. The purchased collars have a floor and ceiling of approximately $0.60 and $0.73, respectively, whereby the Company will incur a loss on the instruments for rates below the floor and a gain for rates above the ceiling.
Derivative Contracts Related to Forecasted Sales
As of September 30, 2024, the Company had no coal derivative contracts related to its forecasted sales. Historically, such financial contracts have included futures and forwards.
Financial Trading Contracts
On a limited basis, the Company may enter coal or freight derivative contracts for trading purposes. Such financial contracts may include futures, forwards and options. The Company held nominal financial trading contracts as of September 30, 2024.
Tabular Derivatives Disclosures
The Company has master netting agreements with certain of its counterparties which allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default or termination. Such netting arrangements reduce the Company’s credit exposure related to these counterparties. For classification purposes, the Company records the net fair value of all the positions with a given counterparty as a net asset or liability in the condensed consolidated balance sheets. As of September 30, 2024 and December 31, 2023, the Company had asset derivatives comprised of foreign currency option contracts with a fair value of $6.4 million and $6.2 million, respectively. The net amount of asset derivatives is included in “Other current assets” in the accompanying condensed consolidated balance sheets.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Currently, the Company does not seek cash flow hedge accounting treatment for its derivative financial instruments and thus changes in fair value are reflected in current earnings. The tables below show the amounts of pretax gains and losses related to the Company’s derivatives and their classification within the accompanying unaudited condensed consolidated statements of operations.
Three Months Ended September 30, 2024
Total gain recognized in incomeLoss realized in income on derivativesUnrealized gain recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$3.6 $(0.1)$3.7 
Total$3.6 $(0.1)$3.7 
Three Months Ended September 30, 2023
Total loss recognized in incomeLoss realized in income on derivativesUnrealized (loss) gain recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$(2.7)$(2.2)$(0.5)
Financial trading contractsRevenue(0.1)(19.7)19.6 
Total$(2.8)$(21.9)$19.1 
Nine Months Ended September 30, 2024
Total loss recognized in incomeLoss realized in income on derivativesUnrealized gain recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$(2.1)$(2.5)$0.4 
Total$(2.1)$(2.5)$0.4 
Nine Months Ended September 30, 2023
Total (loss) gain recognized in income(Loss) gain realized in income on derivativesUnrealized gain (loss) recognized in income on derivatives
Derivative InstrumentClassification
(Dollars in millions)
Foreign currency option contractsOperating costs and expenses$(7.8)$(7.9)$0.1 
Derivative contracts related to forecasted salesRevenue78.1 (80.9)159.0 
Financial trading contractsRevenue— 11.5 (11.5)
Total$70.3 $(77.3)$147.6 
The Company classifies the cash effects of its derivatives within the “Cash Flows From Operating Activities” section of the unaudited condensed consolidated statements of cash flows.
Fair Value Measurements
The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1 - inputs are quoted prices in active markets for the identical assets or liabilities; Level 2 - inputs are other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3 - inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables set forth the hierarchy of the Company’s net asset positions for which fair value is measured on a recurring basis.
 September 30, 2024
 Level 1Level 2Level 3Total
 (Dollars in millions)
Foreign currency option contracts$— $6.4 $— $6.4 
Equity securities0.8 — — 0.8 
Total net assets$0.8 $6.4 $— $7.2 
 December 31, 2023
 Level 1Level 2Level 3Total
 (Dollars in millions)
Foreign currency option contracts$— $6.2 $— $6.2 
Equity securities0.4 — — 0.4 
Total net assets$0.4 $6.2 $— $6.6 
For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker/dealer quotes, published indices, issuer spreads, benchmark securities and other market quotes. In the case of certain debt securities, fair value is provided by a third-party pricing service. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:
•Foreign currency option contracts are valued utilizing inputs obtained in quoted public markets (Level 2) except when credit and non-performance risk is considered to be a significant input, then the Company classifies such contracts as Level 3.
•Derivative contracts related to forecasted sales and financial trading contracts are generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2) except when credit and non-performance risk is considered to be a significant input (greater than 10% of fair value), then the Company classifies as Level 3.
•Investments in equity securities are based on unadjusted quoted prices in active markets (Level 1).
Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of September 30, 2024 and December 31, 2023:
•Cash and cash equivalents, restricted cash, accounts receivable, including those within the Company’s accounts receivable securitization program, margining cash, notes receivable and accounts payable have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.
•Long-term debt fair value estimates are based on observed prices for securities when available (Level 2), and otherwise on estimated borrowing rates to discount the cash flows to their present value (Level 3).
Market risk associated with the Company’s fixed-rate long-term debt relates to the potential reduction in the fair value from an increase in interest rates. The fair value of debt, shown below, is principally based on reported market values and estimates based on interest rates, maturities, credit risk, underlying collateral and completed market transactions.
 September 30, 2024December 31, 2023
 (Dollars in millions)
Total debt at par value$345.1 $342.3 
Less: Unamortized debt issuance costs(6.6)(8.1)
Net carrying amount$338.5 $334.2 
Estimated fair value$501.3 $483.9 
The Company’s risk management function, which is independent of the Company’s coal trading function, is responsible for valuation policies and procedures, with oversight from executive management. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for credit risk. The Company’s exposure to credit risk is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During the nine months ended September 30, 2023, the entity in which the Company held a Level 3 investment in equity securities completed a merger transaction and its shares were exchanged for the shares of the newly-combined entity, which are publicly traded. The Company recorded an impairment loss of $2.0 million upon the exchange of shares.
The Company had no transfers between Levels 1, 2 and 3 during the three and nine months ended September 30, 2024 and 2023. The Company’s policy is to value all transfers between levels using the beginning of period valuation.
(7) Property, Plant, Equipment and Mine Development
The composition of property, plant, equipment and mine development, net, as of September 30, 2024 and December 31, 2023 is set forth in the table below:
September 30, 2024December 31, 2023
(Dollars in millions)
Land and coal interests$2,624.4 $2,475.2 
Buildings and improvements658.1 647.6 
Machinery and equipment2,021.4 1,787.6 
Less: Accumulated depreciation, depletion and amortization(2,290.4)(2,066.3)
Property, plant, equipment and mine development, net$3,013.5 $2,844.1 
At-Risk Assets
The Company identified certain assets with an aggregate carrying value of approximately $207 million at September 30, 2024 in its Other U.S. Thermal segment whose recoverability is most sensitive to customer concentration risk.
(8)  Income Taxes
The Company's effective tax rate before remeasurement for the nine months ended September 30, 2024 is based on the Company’s estimated full year effective tax rate, comprised of expected statutory tax provision, offset by foreign rate differential and changes in valuation allowance. The Company’s income tax provisions of $25.7 million and $46.5 million for the three months ended September 30, 2024 and 2023, respectively, included a tax provision of $1.0 million and a tax benefit of $3.3 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s income tax provisions of $85.2 million and $238.7 million for the nine months ended September 30, 2024 and 2023, respectively, included tax benefits of $2.9 million and $2.6 million, respectively, related to the remeasurement of foreign income tax accounts. The Company’s estimated full year pretax income is expected to be generated in Australia and the U.S. Due to existing valuation allowances, the income tax expense will primarily be related to the Australian income.
The Company recognizes interest and penalties related to unrecognized tax benefits in its income tax provision. No penalties or interest were recognized during the three months ended September 30, 2024. During the nine months ended September 30, 2024, the Company’s net unrecognized tax benefits decreased by $1.3 million and its gross interest and penalties decreased by $6.1 million due to expiration of statutes.
(9)     Long-term Debt 
The Company’s total indebtedness as of September 30, 2024 and December 31, 2023 consisted of the following:
Debt Instrument (defined below, as applicable)September 30, 2024December 31, 2023
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes)
$320.0 $320.0 
Finance lease obligations25.1 22.3 
Less: Debt issuance costs(6.6)(8.1)
338.5 334.2 
Less: Current portion of long-term debt14.8 13.5 
Long-term debt$323.7 $320.7 

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2028 Convertible Notes
On March 1, 2022, through a private offering, the Company issued the 2028 Convertible Notes in the aggregate principal amount of $320.0 million. 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 and available cash to redeem its then-existing senior secured notes, and to pay related premiums, fees and expenses relating to the offering and redemptions. The Company capitalized $11.2 million of debt issuance costs related to the offering, which are being amortized over the terms of the notes.
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 bear interest at a rate of 3.250% per year, payable semi-annually in arrears on March 1 and September 1 of each year.
The initial conversion rate for the 2028 Convertible Notes was 50.3816 shares of the Company’s common stock per $1,000 principal amount of 2028 Convertible Notes, which represented an initial conversion price of approximately $19.85 per share of the Company’s common stock. The terms of the indenture require conversion rate adjustments upon the payment of dividends to holders of the Company’s common stock once such cumulative dividends impact the conversion rate by at least 1%. Effective February 21, 2024, the conversion rate was increased to 51.0440 shares of the Company’s common stock per $1,000 principal amount of 2028 Convertible Notes, which represented an adjusted conversion price of approximately $19.59 per share. Under the applicable conversion rate formula, the cumulative $0.150 per share dividends declared and paid during the six months ended September 30, 2024 yielded a revised conversion rate of 51.3840 shares per $1,000 principal amount of 2028 Convertible Notes, which did not meet the 1% threshold to impact the existing conversion rate of 51.0440. The conversion rate may be impacted prospectively, based upon cumulative dividends paid. The conversion rate is also subject to further adjustment under certain circumstances in accordance with the terms of the indenture.
During the first three quarters of 2024, the Company’s reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes were not convertible at the option of the holders during the second or third quarters of 2024, and will not be similarly convertible during the fourth quarter of 2024.
As of September 30, 2024, the if-converted value of the 2028 Convertible Notes exceeded the principal amount by $116.4 million.
Revolving Credit Facility
The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto. The Company paid aggregate debt issuance costs of $9.7 million.
The revolving commitments and any related loans, if applicable (any such loans, the Revolving Loans), established by the 2024 Credit Agreement terminate or mature, as applicable, on January 18, 2028, subject to certain conditions relating to the Company’s outstanding 2028 Convertible Notes. The Revolving Loans bear interest at a secured overnight financing rate (SOFR) plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option. Letters of credit issued under the 2024 Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.50% to 4.25% plus a fronting fee equal to 0.125% per annum. Unused capacity under the 2024 Credit Agreement bears a commitment fee of 0.50% per annum.
As of September 30, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $98.6 million outstanding as of September 30, 2024. These letters of credit support the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees as further described in Note 12. “Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $221.4 million at September 30, 2024.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The 2024 Credit Agreement contains customary covenants that, among other things and subject to certain exceptions (including compliance with financial ratios), may limit the Company and its subsidiaries’ ability to incur additional indebtedness, make certain restricted payments or investments, sell or otherwise dispose of assets, enter into transactions with affiliates, create or incur liens, and merge, consolidate or sell all or substantially all of their assets. The 2024 Credit Agreement is secured by substantially all assets of the Company and its U.S. subsidiaries, as well as a pledge of two Australian subsidiaries.
Interest Charges
The following table presents the components of the Company’s interest expense related to its indebtedness and financial assurance instruments such as surety bonds and letters of credit. Additionally, the table sets forth the amount of cash paid for interest, net of capitalized interest and the amount of non-cash interest expense primarily related to the amortization of debt issuance costs.
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
2028 Convertible Notes$2.6 $2.6 $7.8 $7.8 
Finance lease obligations0.4 0.4 1.3 1.4 
Financial assurance instruments5.8 8.9 20.7 28.9 
Amortization of debt issuance costs0.6 0.7 4.0 2.9 
Receivables securitization program0.5 0.9 1.9 2.8 
Capitalized interest(2.7)— (4.4)— 
Other2.5 0.3 3.8 1.7 
Interest expense, net of capitalized interest$9.7 $13.8 $35.1 $45.5 
Cash paid for interest, net of capitalized interest$8.5 $14.8 $32.6 $56.7 
Non-cash interest expense$0.8 $0.7 $4.0 $4.0 
Covenant Compliance
The Company was compliant with all relevant covenants under its debt and other finance agreements at September 30, 2024.
(10) Pension and Postretirement Benefit Costs
The components of net periodic pension and postretirement benefit costs, excluding the service cost for benefits earned, are included in “Net periodic benefit credit, excluding service cost” in the unaudited condensed consolidated statements of operations.
Net periodic pension cost included the following components:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Service cost for benefits earned$0.1 $0.1 $0.1 $0.1 
Interest cost on projected benefit obligation1.7 3.6 4.9 18.4 
Expected return on plan assets(1.3)(3.1)(3.7)(16.3)
Net periodic pension cost$0.5 $0.6 $1.3 $2.2 
At January 1, 2023, the Company had two qualified pension plans. During the year ended December 31, 2023, the Company settled its pension obligation for one of its qualified plans. Refer to Note 14. “Pension and Savings Plans” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, for information regarding the settlement of the plan’s obligation.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Annual contributions to the remaining qualified plan are made in accordance with minimum funding standards and the Company’s agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006. As of September 30, 2024, the Company’s remaining qualified plan was expected to be at or above the Pension Protection Act thresholds. The Company is not required to make any cash contributions to its remaining qualified pension plan in 2024 based on minimum funding requirements and does not expect to make any discretionary cash contributions in 2024.
Net periodic postretirement benefit credit included the following components:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Service cost for benefits earned$0.1 $0.1 $0.3 $0.4 
Interest cost on accumulated postretirement benefit obligation2.3 2.6 6.9 7.6 
Expected return on plan assets(0.1)(0.1)(0.3)(0.4)
Amortization of prior service credit(13.3)(13.5)(39.8)(40.3)
Net periodic postretirement benefit credit$(11.0)$(10.9)$(32.9)$(32.7)
The Company has established a Voluntary Employees’ Beneficiary Association (VEBA) trust to pre-fund a portion of benefits for non-represented retirees. The Company does not expect to make any discretionary contributions to the VEBA trust in 2024 and plans to utilize a portion of VEBA assets to make certain benefit payments.
(11) Earnings per Share (EPS)
Basic EPS is computed based on the weighted average number of shares of common stock outstanding during the period. Diluted EPS is computed based on the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding. As such, the Company includes the 2028 Convertible Notes and share-based compensation awards in its potentially dilutive securities. Generally, dilutive securities are not included in the computation of loss per share when a company reports a net loss from continuing operations as the impact would be anti-dilutive.
For all but performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted.
A conversion of the 2028 Convertible Notes may result in payment in the Company’s common stock. For diluted EPS purposes, the potentially dilutive common stock is assumed to have been converted at the beginning of the period (or at the time of issuance, if later). In periods where the potentially dilutive common stock is included in the computation of diluted EPS, the numerator will be adjusted to add back tax adjusted interest expense, which includes the amortization of debt issuance costs, related to the convertible debt.
The computation of diluted EPS excluded aggregate share-based compensation awards of less than 0.1 million for the three and nine months ended September 30, 2024 and 2023 because to do so would have been anti-dilutive for those periods. Because the potential dilutive impact of such share-based compensation awards is calculated under the treasury stock method, anti-dilution generally occurs when the exercise prices or unrecognized compensation cost per share of such awards are higher than the Company’s average stock price during the applicable period. Anti-dilution also occurs when a company reports a net loss from continuing operations, and the dilutive impact of all share-based compensation awards are excluded accordingly.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.
Three Months Ended September 30,Nine Months Ended September 30,
 2024202320242023
(In millions, except per share data)
Basic EPS numerator: 
Income from continuing operations, net of income taxes$112.5 $128.8 $369.0 $617.0 
Less: Net income attributable to noncontrolling interests10.2 11.4 25.4 49.3 
Income from continuing operations attributable to common stockholders102.3 117.4 343.6 567.7 
(Loss) income from discontinued operations, net of income taxes(1.0)2.5 (3.3)(0.1)
Net income attributable to common stockholders$101.3 $119.9 $340.3 $567.6 
Diluted EPS numerator:
Income from continuing operations, net of income taxes$112.5 $128.8 $369.0 $617.0 
Add: Tax adjusted interest expense related to 2028 Convertible Notes3.1 3.0 9.2 9.1 
Less: Net income attributable to noncontrolling interests10.2 11.4 25.4 49.3 
Income from continuing operations attributable to common stockholders105.4 120.4 352.8 576.8 
(Loss) income from discontinued operations, net of income taxes(1.0)2.5 (3.3)(0.1)
Net income attributable to common stockholders$104.4 $122.9 $349.5 $576.7 
EPS denominator: 
Weighted average shares outstanding — basic
124.9 133.2 126.3 140.0 
Dilutive impact of share-based compensation awards0.4 0.6 0.5 0.6 
Dilutive impact of 2028 Convertible Notes16.3 16.1 16.3 16.1 
Weighted average shares outstanding — diluted141.6 149.9 143.1 156.7 
Basic EPS attributable to common stockholders:
 
Income from continuing operations$0.82 $0.88 $2.72 $4.06 
(Loss) income from discontinued operations(0.01)0.02 (0.03)(0.01)
Net income attributable to common stockholders$0.81 $0.90 $2.69 $4.05 
 
Diluted EPS attributable to common stockholders: 
Income from continuing operations$0.74 $0.80 $2.47 $3.68 
(Loss) income from discontinued operations— 0.02 (0.03)— 
Net income attributable to common stockholders$0.74 $0.82 $2.44 $3.68 
(12) Financial Instruments and Other Guarantees
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. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance 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 the accompanying condensed consolidated balance sheets.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.
 September 30, 2024
 Reclamation Support
Other Support (1)
Total
 (Dollars in millions)
Surety bonds$932.2 $107.7 $1,039.9 
Letters of credit (2)
55.2 103.8 159.0 
987.4 211.5 1,198.9 
Less: Letters of credit in support of surety bonds (3)
(55.2)(12.4)(67.6)
Obligations supported, net$932.2 $199.1 $1,131.3 
(1)    Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.
(2)    Amounts do not include cash-collateralized letters of credit.
(3)    Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers.
Surety Agreement Amendment and Collateral Requirements
In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the April 2023 amendment, the Company and its surety providers agreed to a maximum aggregate collateral amount of $721.8 million based upon bonding levels at the effective date of the amendment. This maximum collateral amount will vary prospectively as bonding levels increase or decrease. The amendment extended the agreement through December 31, 2026. In order to maintain the maximum collateral agreement, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers, which was $507.3 million at September 30, 2024. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company’s 2028 Convertible Notes is deemed to be funded debt. The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. The Company is in compliance with such requirements at September 30, 2024.
To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023. The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider. The amendment became effective on April 14, 2023, when the Company terminated a then-existing credit agreement which, as amended, provided for $237.2 million of capacity for irrevocable standby letters of credit (LC Facility).
LC Facility
The now-terminated LC Facility had an original capacity of $324.0 million and was subsequently amended at various dates to reduce its capacity and effect certain other changes, including in February 2023 to reduce capacity by $65.0 million, accelerate the expiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any reduction of commitments thereunder prior to July 29, 2023. The Company recorded early debt extinguishment losses of $8.8 million during the nine months ended September 30, 2023, primarily as a result of the February 2023 amendment and subsequent termination.
Prior to its termination, undrawn letters of credit under the LC Facility bore interest at 6.00% per annum and unused commitments were subject to a 0.50% per annum commitment fee.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accounts Receivable Securitization
In 2017, the Company entered into the Sixth Amended and Restated Receivables Purchase Agreement, as amended from time to time (the Receivables Purchase Agreement). The receivables securitization program authorized under the agreement (Securitization Program) is subject to customary events of default. The Receivables Purchase Agreement was amended in February 2023 to increase the available funding capacity from $175.0 million to $225.0 million and adjust the relevant interest rate for borrowings to a SOFR plus an applicable margin. Such funding is accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of collateral and the trade receivables underlying the program. Funding capacity under the Securitization Program may also be utilized for letters of credit in support of other obligations, which has been the Company’s primary utilization.
Borrowings under the Securitization Program bear interest at a SOFR plus 2.1% per annum and remain outstanding throughout the term of the agreement, subject to the Company maintaining sufficient eligible receivables.
At September 30, 2024, the Company had no outstanding borrowings and $60.4 million of letters of credit outstanding under the Securitization Program. Availability under the Securitization Program, which is adjusted for certain ineligible receivables, was $95.6 million at September 30, 2024. The Company was not required to post cash collateral under the Securitization Program at September 30, 2024.
The Company incurred interest and fees associated with the Securitization Program of $0.5 million and $0.9 million during the three months ended September 30, 2024 and 2023, respectively, and $1.9 million and $2.8 million during the nine months ended September 30, 2024 and 2023, respectively, which have been recorded as “Interest expense, net of capitalized interest” in the accompanying unaudited condensed consolidated statements of operations.
Credit Support Facilities
In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to 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 variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At September 30, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million.
In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. During the nine months ended September 30, 2024, the Company capitalized $1.4 million of debt issuance costs related to these bank guarantee facilities. The Company receives a variable deposit rate on the amount of cash collateral posted in support of the bank guarantee facilities, which mature at various dates between 2026 and 2029. At September 30, 2024, the bank guarantee facilities were backed by cash of $187.9 million.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Cash and Collateral
The following table summarizes the Company’s “Restricted cash and collateral” in the accompanying condensed consolidated balance sheets. Restricted cash balances are held in controlled accounts with minimum balance requirements; withdrawals are subject to the approval of account beneficiaries, such as the Company’s surety providers, who have perfected security interests in the funds. The Company’s other cash collateral generally includes deposits held by regulatory authorities or financial institutions over which the Company has no control or ability to access. Portions of the restricted cash balances and deposits are held in accounts denominated in Australian dollars.
September 30, 2024December 31, 2023
 (Dollars in millions)
Restricted cash (1)
Surety trust accounts (2)
$397.6 $444.0 
Credit support facilities (2) (3)
308.0 236.9 
705.6 680.9 
Other cash collateral (1)
Deposits with regulatory authorities for reclamation and other obligations (3)
133.4 276.7 
133.4 276.7 
Restricted cash and collateral$839.0 $957.6 
(1)    Restricted cash balances are combined with unrestricted cash and cash equivalents in the accompanying unaudited condensed consolidated statements of cash flows; changes between unrestricted cash and cash equivalents and restricted cash balances are thus not reflected in the operating, investing or financing activities therein. Changes in other cash collateral balances are reflected as operating activities therein.
(2)    Surety trust accounts, the funding for collateralized letters of credit and cash supporting the bank guarantee facilities are comprised of highly liquid investments with original maturities of three months or less; interest and other earnings on such funds accrue to the Company.
(3)    At September 30, 2024, the Australian dollar denominated balances supporting the bank guarantee facilities and the deposits with regulatory authorities were $271 million and $192 million, respectively. At December 31, 2023, the Australian dollar denominated balances supporting the bank guarantee facilities and the deposits with regulatory authorities were $95 million and $404 million, respectively.
(13) Commitments and Contingencies
Commitments
Unconditional Purchase Obligations
As of September 30, 2024, purchase commitments for capital expenditures were $81.3 million, all of which is obligated within the next 12 months.
There were no other material changes to the Company’s commitments from the information provided in Note 21. “Commitments and Contingencies” to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023.
Contingencies
From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities. The Company discusses its significant legal proceedings below, including ongoing proceedings and those that impacted the Company’s consolidated results of operations for the periods presented.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Litigation and Matters Relating to Continuing Operations
Metropolitan Mine Stormwater Discharge. Significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site resulted in stormwater being discharged from the mine site on several occasions in 2021 and 2022. On September 6, 2023, the Environment Protection Authority commenced a prosecution for five breaches of the Protection of the Environment Operations Act 1997 relating to the stormwater discharges. On March 15, 2024, the Company pled guilty to two of the charges related to water pollution, and two charges related to a failure to adequately maintain plant and equipment were consolidated into one charge to which the Company also pled guilty. No plea has been entered for the remaining charge that has been held over to a sentencing hearing that is scheduled for November 2024. Penalties will be determined at that sentencing hearing. During the nine months ended September 30, 2024, the Company recorded an immaterial provision to establish a current liability that the Company believes is probable and reasonably estimable.
Oregon Climate Change Lawsuit. On July 20, 2023, Peabody Energy was served with a summons issued on behalf of Multnomah County, Oregon. The complaint sought damages from the Company and other major energy producers for allegedly causing an “extreme heat event” in Multnomah County in late June and early July 2021. The causes of action, pursuant to Oregon state law, included a failure to warn, false or misleading advertisement and public nuisance. In July 2024, Peabody was dismissed from this case, without prejudice.
Other
At times, the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its consolidated financial condition, results of operations or cash flows. The Company reassesses the probability and estimability of contingent losses as new information becomes available.
(14) Segment Information
The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin, Other U.S. Thermal and Corporate and Other. The Company’s CODM, defined as its Chief Executive Officer, uses Adjusted EBITDA as the primary metric to measure the segments’ operating performance and allocate resources.
Adjusted EBITDA is a non-GAAP financial measure defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the segments’ operating performance, as displayed in the reconciliation below. Management believes this non-GAAP performance measure is also used by investors to measure the Company’s operating performance. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Reportable segment results were as follows:
Three Months Ended September 30,Nine Months Ended September 30,
 2024202320242023
 (Dollars in millions)
Revenue:  
Seaborne Thermal$313.2 $297.4 $904.6 $1,043.4 
Seaborne Metallurgical242.5 247.0 783.8 907.9 
Powder River Basin305.3 313.0 781.3 878.0 
Other U.S. Thermal216.7 228.2 610.3 677.5 
Corporate and Other10.3 (6.7)33.6 204.9 
Total$1,088.0 $1,078.9 $3,113.6 $3,711.7 
Adjusted EBITDA:  
Seaborne Thermal$120.0 $115.5 $318.2 $477.0 
Seaborne Metallurgical27.8 78.6 219.7 271.9 
Powder River Basin51.7 54.1 85.9 116.1 
Other U.S. Thermal28.4 49.1 110.3 165.2 
Corporate and Other(3.1)(27.3)(39.1)(11.4)
Total$224.8 $270.0 $695.0 $1,018.8 
A reconciliation of consolidated income from continuing operations, net of income taxes to Adjusted EBITDA follows:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Income from continuing operations, net of income taxes$112.5 $128.8 $369.0 $617.0 
Depreciation, depletion and amortization84.7 82.3 247.4 239.2 
Asset retirement obligation expenses12.9 15.4 38.7 46.3 
Restructuring charges1.9 0.9 2.1 3.0 
Asset impairment— — — 2.0 
Provision for NARM and Shoal Creek losses— 3.3 3.7 37.0 
Shoal Creek insurance recovery - property damage— — (28.7)— 
Changes in amortization of basis difference related to equity affiliates(0.4)(0.5)(1.1)(1.2)
Interest expense, net of capitalized interest9.7 13.8 35.1 45.5 
Net loss on early debt extinguishment— — — 8.8 
Interest income(17.7)(20.3)(53.7)(56.5)
Unrealized gains on derivative contracts related to forecasted sales— — — (159.0)
Unrealized (gains) losses on foreign currency option contracts(3.7)0.5 (0.4)(0.1)
Take-or-pay contract-based intangible recognition(0.8)(0.7)(2.3)(1.9)
Income tax provision25.7 46.5 85.2 238.7 
Adjusted EBITDA$224.8 $270.0 $695.0 $1,018.8 

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(15) Other Events
Share Repurchases
During the three and nine months ended September 30, 2024, the Company repurchased approximately 4.5 million shares and 7.7 million shares, respectively, of its common stock for $100.0 million and $180.5 million, respectively, including commission fees. The Company had accrued excise taxes of $5.0 million related to share repurchases, which were unpaid at September 30, 2024. The Company includes commission fees and excise taxes, as incurred, with the cost of treasury stock. At September 30, 2024, $469.6 million remained available under its share repurchase program.
Wards Well Acquisition
The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well) which are adjacent to the Company’s Centurion Mine in Queensland, Australia. The acquisition, which was accounted for as an asset acquisition, was completed on April 16, 2024. The acquired asset was measured at the cost of the acquisition based on the total consideration, allocated on the basis of relative fair value. The total consideration of $153.4 million, consisting of cash consideration of $134.4 million, cash transaction costs of $9.4 million and the non-cash settlement of existing receivables with the acquiree of $9.6 million, was recorded in “Property, plant, equipment and mine development, net” in the condensed consolidated balance sheets as of September 30, 2024.
The agreement also includes an initial contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of Wards Well and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining Wards Well. The Company will adjust the cost basis of the assets acquired if and when the contingent royalty is paid or becomes payable.
North Antelope Rochelle Mine Tornado
On June 23, 2023, the Company’s North Antelope Rochelle Mine sustained damage from a tornado which led to a temporary suspension of operations. The mine resumed operations on June 25, 2023. During the three and nine months ended September 30, 2023, the Company recorded a provision for loss of $3.3 million and $8.3 million, respectively, related to the tornado damage. The combined provision includes $4.0 million for materials and supplies inventories, $1.0 million for buildings and equipment and $3.3 million for incremental repair costs. During the nine months ended September 30, 2024, the Company recorded $3.7 million for incremental repair costs related to the tornado damage. During the three months ended September 30, 2024, the Company did not record a provision related to the tornado damage.
Shoal Creek
On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. On June 20, 2023, the Company announced that the Shoal Creek Mine, in coordination with the Mine Safety and Health Administration, had safely completed localized sealing of the affected area of the mine. During the nine months ended September 30, 2023, the Company recorded a provision for loss of $28.7 million related to the fire, which included $17.8 million related to longwall development and other costs and $10.9 million for equipment deemed inoperable within the affected area of the mine.
In October 2023, the Company filed an insurance claim against applicable insurance policies with combined business interruption and property loss limits of $125 million above a $50 million deductible. During June 2024, the Company reached a settlement with its insurers and various re-insurers and recognized a $109.5 million insurance recovery which the Company included in its results of operations during the nine months ended September 30, 2024.
During the nine months ended September 30, 2024, the Company collected $103.8 million of the insurance recovery. The Company classified $10.9 million of the recovery within the “Cash Flows From Investing Activities” section of the unaudited condensed consolidated statements of cash flows since this portion of the recovery related to equipment damage for which the Company previously recognized the provision for loss. The remaining $5.7 million of the insurance recovery was recorded as a receivable within “Accounts receivable, net” in the condensed consolidated balance sheets as of September 30, 2024 and was subsequently collected in October 2024.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Port and Rail Capacity Assignment
During the nine months ended September 30, 2023, the Company entered into an agreement to assign the right to its excess port and rail capacity related to its Centurion Mine to an unrelated party in exchange for $30.0 million Australian dollars. Half of such amount was received by the Company upon entry into the agreement, and half was payable in June 2024, subject to certain conditions. In connection with the transaction, the Company recorded revenue of $19.2 million during the nine months ended September 30, 2023. In association with the completion of the Wards Well acquisition described above, the remaining receivable was settled as part of the consideration on April 16, 2024.

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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” of Part II of this Quarterly Report on Form 10-Q, Item 1A. “Risk Factors” of Part II of its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2024 filed with the SEC on August 8, 2024 and Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of Part I of its Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 23, 2024. 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 the chief operating decision maker as the primary metric to measure each of the 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 reporting segment. These metrics are used by management to measure each of its reporting segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting 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 Available Free Cash Flow (AFCF) which is also a non-GAAP financial measure. AFCF is used by management as a measure of 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. 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 2023, the Company produced and sold 126.7 million and 126.2 million tons of coal, respectively, from continuing operations. At September 30, 2024, 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; trades coal and freight-related contracts; and since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage.
The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin, Other U.S. Thermal 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 September 30, 2024 is set forth in the table below.
The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2024 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 quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2024 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.
HighLowAverageSeptember 30, 2024November 4, 2024
Premium HCC (1)
$258.00 $180.00 $210.67 $204.75 $203.00 
Premium PCI coal (1)
200.00 140.00 174.20 147.00 160.00 
Newcastle index thermal coal (1)
150.05 132.81 140.80 140.56 145.88 
API 5 index thermal coal (1)
88.68 86.41 87.45 88.68 90.50 
PRB 8,800 Btu/Lb coal (2)
13.90 13.70 13.84 13.90 14.00 
Illinois Basin 11,500 Btu/Lb coal (2)
41.75 40.00 41.12 41.00 42.75 
(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 continue to be impacted by the ongoing Russian-Ukrainian conflict. As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the nine months ended September 30, 2024 presented herein may not be indicative of their ultimate impacts.

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Within the seaborne metallurgical coal market, coking coal prices have retreated from a high base during the nine months ended September 30, 2024. Parts of the global steel market have reported tepid demand and thin profit margins during this period, restricting demand growth for metallurgical coal. In China, continued weakness in the property sector has contributed to lower domestic steel demand and steel production in 2024 and has also supported increased steel exports. The increased availability of competitively priced Chinese imports has pressured steel margins for steel producers in other countries, although India has recorded year-over-year production growth due to its increased domestic consumption. Meanwhile, global supply of coking coal has been relatively stable during the nine months ended September 30, 2024, and has met global demand despite various disruption events, such as a fire at the Grosvenor Mine in Australia and shipping interruptions at the U.S.’s Baltimore, Maryland port. In the PCI segment, prices were initially under pressure early in the year with a wide discount to coking coal caused in part by reduced steel making productivity targets under thin margin conditions. PCI relativities to coking coal have since improved. In September 2024, increased government stimulus activity in China has supported an uptick in Chinese ferrous futures prices, which has in turn contributed to improved spot pricing for seaborne metallurgical coal. In the coming period, seasonal restocking patterns and ongoing economic stimulus may lend support to metallurgical coal pricing. Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of exports from Australia and economic performance in China, India and elsewhere.
Within the seaborne thermal coal market, global thermal coal prices continued to remain stable during the nine months ended September 30, 2024, driven by healthy supply meeting elevated demand in Asian markets. In China, overall total generation demand has been elevated while domestic coal production has remained relatively flat, which has driven stronger coal import demand year-over-year through the nine months ended September 30, 2024. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Looking ahead, global thermal coal markets remain turbulent amid tighter supply ahead of winter restocking requirements in the Northern Hemisphere, as well as volatile global natural gas markets.
In the U.S., overall electricity demand increased approximately 3% year-over-year. Through the nine months ended September 30, 2024, electricity generation from thermal coal has decreased year-over-year driven by continued low natural gas prices and stronger renewable generation. Coal’s share of electricity generation has declined to approximately 15% for the nine months ended September 30, 2024, while wind and solar’s combined generation share is at 17% and the share of natural gas generation has remained level at 43%. U.S. coal inventories have declined through September 30, 2024, resulting in stockpiles declining more than 10 million tons below levels seen at the end of 2023. During the nine months ended September 30, 2024, utility consumption of PRB coal has declined compared to the prior year period.
Centurion Mine
Peabody’s redevelopment of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned. Through September 30, 2024, two continuous miners units have been commissioned, the first development coal was produced and the first coal was washed. The first coal shipment from the Centurion Mine is expected in the fourth quarter of 2024, and the Company is targeting the commencement of longwall production in the first quarter of 2026. Approximately $250 million of the $489 million of capital expenditures to reach longwall production has been completed as of September 30, 2024.
Other
Wards Well Acquisition. The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well) which are adjacent to the Company’s Centurion Mine in Queensland, Australia. The acquisition was completed on April 16, 2024 for total consideration of $153.4 million, consisting of cash consideration of $134.4 million, cash transaction costs of $9.4 million and the non-cash settlement of existing receivables with the acquiree of $9.6 million.
The agreement also includes an initial contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of Wards Well and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining Wards Well.
Shoal Creek Insurance Recovery. On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. On June 20, 2023, the Company announced that the Shoal Creek Mine, in coordination with the Mine Safety and Health Administration, had safely completed localized sealing of the affected area of the mine.

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In October 2023, the Company filed an insurance claim against applicable insurance policies with combined business interruption and property loss limits of $125 million above a $50 million deductible. During June 2024, the Company reached a settlement with its insurers and various re-insurers and recognized a $109.5 million insurance recovery which the Company included in its results of operations during the nine months ended September 30, 2024.
Results of Operations
Three and Nine Months Ended September 30, 2024 Compared to the Three and Nine Months Ended September 30, 2023
Summary
The decrease in income from continuing operations, net of income taxes for the three months ended September 30, 2024 compared to the same period in the prior year ($16.3 million) was driven by higher operating costs and expenses ($42.1 million), partially offset by a lower year-over-year provision for taxes ($20.8 million) and higher revenue ($9.1 million) due to higher seaborne thermal coal pricing.
The decrease in income from continuing operations, net of income taxes for the nine months ended September 30, 2024 compared to the same period in the prior year ($248.0 million) was driven by lower revenue ($598.1 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. This unfavorable variance was partially offset by a lower tax provision ($153.5 million), the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($48.4 million) and a lower year-over-year provision for losses at the NARM and Shoal Creek Mines ($33.3 million).
Adjusted EBITDA for the three and nine months ended September 30, 2024 reflected year-over-year decreases of $45.2 million and $323.8 million, respectively.
Tons Sold
The following table presents tons sold by operating segment:
Three Months Ended September 30,(Decrease) Increase
to Volumes		Nine Months Ended September 30,Increase (Decrease)
to Volumes
 20242023Tons%20242023Tons%
 (Tons in millions)(Tons in millions)
Seaborne Thermal4.1 4.2 (0.1)(2)%12.2 11.8 0.4 3 %
Seaborne Metallurgical1.7 1.5 0.2 13 %5.1 4.8 0.3 6 %
Powder River Basin22.1 22.7 (0.6)(3)%56.6 63.6 (7.0)(11)%
Other U.S. Thermal4.0 4.2 (0.2)(5)%10.9 12.5 (1.6)(13)%
Total tons sold from operating segments31.9 32.6 (0.7)(2)%84.8 92.7 (7.9)(9)%
Corporate and Other— — — n.m.0.1 0.3 (0.2)(67)%
Total tons sold31.9 32.6 (0.7)(2)%84.9 93.0 (8.1)(9)%

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Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Three Months Ended September 30,Increase
(Decrease)		Nine Months Ended September 30,(Decrease)
Increase
 20242023$%20242023$%
Revenue per Ton (1)
Seaborne Thermal$76.21 $71.38 $4.83 7 %$73.99 $89.06 $(15.07)(17)%
Seaborne Metallurgical144.60 162.02 (17.42)(11)%154.31 189.50 (35.19)(19)%
Powder River Basin 13.84 13.79 0.05 — %13.82 13.80 0.02 — %
Other U.S. Thermal53.52 53.89 (0.37)(1)%55.92 54.12 1.80 3 %
Costs per Ton (1)(2)
Seaborne Thermal$47.01 $43.68 $3.33 8 %$47.96 $48.35 $(0.39)(1)%
Seaborne Metallurgical128.04 110.38 17.66 16 %126.98 132.74 (5.76)(4)%
Powder River Basin 11.50 11.41 0.09 1 %12.30 11.98 0.32 3 %
Other U.S. Thermal46.50 42.28 4.22 10 %45.81 40.92 4.89 12 %
Adjusted EBITDA Margin per Ton (1)(2)
Seaborne Thermal$29.20 $27.70 $1.50 5 %$26.03 $40.71 $(14.68)(36)%
Seaborne Metallurgical16.56 51.64 (35.08)(68)%27.33 56.76 (29.43)(52)%
Powder River Basin 2.34 2.38 (0.04)(2)%1.52 1.82 (0.30)(16)%
Other U.S. Thermal7.02 11.61 (4.59)(40)%10.11 13.20 (3.09)(23)%
(1)This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; insurance recoveries; and certain other costs related to post-mining activities.
Revenue
The following table presents revenue by reporting segment:
Three Months Ended September 30,Increase (Decrease) to RevenueNine Months Ended September 30,Decrease to Revenue
20242023$%20242023$%
 (Dollars in millions)(Dollars in millions) 
Seaborne Thermal$313.2 $297.4 $15.8 5 %$904.6 $1,043.4 $(138.8)(13)%
Seaborne Metallurgical242.5 247.0 (4.5)(2)%783.8 907.9 (124.1)(14)%
Powder River Basin305.3 313.0 (7.7)(2)%781.3 878.0 (96.7)(11)%
Other U.S. Thermal216.7 228.2 (11.5)(5)%610.3 677.5 (67.2)(10)%
Corporate and Other10.3 (6.7)17.0 254 %33.6 204.9 (171.3)(84)%
Revenue$1,088.0 $1,078.9 $9.1 1 %$3,113.6 $3,711.7 $(598.1)(16)%
Seaborne Thermal. Segment revenue increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable mix variances. Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($214.2 million), partially offset by favorable export volume ($75.4 million).
Seaborne Metallurgical. Segment revenue decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to unfavorable realized prices ($28.1 million and $195.1 million, respectively), partially offset by favorable volume and mix variances ($23.6 million and $71.0 million, respectively).

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Powder River Basin. Segment revenue decreased during the three months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume. Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume ($91.5 million) resulting from decreased demand driven by low natural gas pricing and mild weather and unfavorable realized prices ($6.7 million), partially offset by increased revenue from sales contract cancellation settlements.
Other U.S. Thermal. Segment revenue decreased during the three months ended September 30, 2024 compared to the same period in the prior year primarily due to unfavorable realized prices ($10.9 million) due in part to mix variances. Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume ($71.9 million) resulting from decreased demand driven by low natural gas pricing and mild weather and unfavorable realized prices ($10.0 million), partially offset by increased revenue from sales contract cancellation settlements ($14.7 million).
Corporate and Other. Segment revenue increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable results from trading activities ($16.4 million). Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($159.0 million) as all derivative contracts settled in 2023 and prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company’s reporting segments:
 Three Months Ended September 30,Increase (Decrease) to Segment Adjusted EBITDANine Months Ended September 30,Decrease to Segment Adjusted EBITDA
20242023$%20242023$%
 (Dollars in millions) (Dollars in millions) 
Seaborne Thermal$120.0 $115.5 $4.5 4 %$318.2 $477.0 $(158.8)(33)%
Seaborne Metallurgical27.8 78.6 (50.8)(65)%219.7 271.9 (52.2)(19)%
Powder River Basin51.7 54.1 (2.4)(4)%85.9 116.1 (30.2)(26)%
Other U.S. Thermal28.4 49.1 (20.7)(42)%110.3 165.2 (54.9)(33)%
Corporate and Other(3.1)(27.3)24.2 89 %(39.1)(11.4)(27.7)(243)%
Adjusted EBITDA (1)
$224.8 $270.0 $(45.2)(17)%$695.0 $1,018.8 $(323.8)(32)%
(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. Segment Adjusted EBITDA increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable mix variances, partially offset by lower realized prices net of sales price sensitive costs. Segment Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($203.3 million), partially offset by favorable volume and mix variances ($39.3 million).
Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the three months ended September 30, 2024 compared to the same period in the prior year due to unfavorable operational costs ($42.2 million) and lower realized prices net of sales price sensitive costs ($26.4 million). These decreases were offset by favorable volume ($20.9 million). Segment Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($164.5 million) and unfavorable operational costs ($92.7 million). These decreases were offset by favorable volume ($104.0 million) driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, despite the lock outages during 2024; and the Shoal Creek insurance recovery ($80.8 million) further discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements

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Powder River Basin. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to increased lease spend ($4.6 million and $10.0 million, respectively), unfavorable volume ($4.0 million and $49.3 million, respectively) and increased overburden removal costs ($3.6 million and $10.9 million, respectively). These decreases were offset by favorable commodity pricing ($7.7 million and $15.6 million, respectively) and lower costs for materials, services, repairs and labor ($6.3 million and $28.5 million, respectively).
Other U.S. Thermal. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to unfavorable volume ($12.2 million and $52.4 million, respectively), lower realized prices net of sales price sensitive costs ($10.5 million and $11.1 million, respectively) and higher costs for materials, services, repairs and labor ($3.7 million and $10.2 million, respectively). These decreases were offset by favorable mine sequencing ($3.5 million and $16.0 million, respectively) and increased sales contract cancellation settlements ($1.6 million and $14.7 million, respectively).
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Three Months Ended September 30,(Decrease) Increase to Adjusted EBITDANine Months Ended September 30,(Decrease) Increase to Adjusted EBITDA
20242023$%20242023$%
 (Dollars in millions)(Dollars in millions)
Middlemount (1)
$1.8 $7.7 $(5.9)(77)%$2.9 $13.7 $(10.8)(79)%
Resource management activities (2)
2.2 3.1 (0.9)(29)%16.5 11.4 5.1 45 %
Selling and administrative expenses
(20.6)(21.5)0.9 4 %(64.7)(66.0)1.3 2 %
Other items, net (3)
13.5 (16.6)30.1 181 %6.2 29.5 (23.3)(79)%
Corporate and Other Adjusted EBITDA
$(3.1)$(27.3)$24.2 89 %$(39.1)$(11.4)$(27.7)(243)%
(1)Middlemount’s results are before the impact of related changes in amortization of basis difference.
(2)Includes gains (losses) on certain surplus coal reserve, coal resource 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, results from the Company’s equity method investment in R3 Renewables LLC, costs associated with suspended operations including the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities.
Corporate and Other Adjusted EBITDA increased during the three months ended September 30, 2024 compared to the same period in the prior year due to the favorable net impact of foreign currency rate changes ($17.1 million) and favorable trading results ($14.4 million), partially offset by unfavorable variances in Middlemount’s results driven by lower sales volume and pricing.
Corporate and Other Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; unfavorable trading results ($11.1 million); and unfavorable variances in Middlemount’s results driven by lower sales volume and pricing. These decreases were partially offset by the favorable net impact of foreign currency rate changes ($11.6 million).

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Income From Continuing Operations, Net of Income Taxes
The following table presents income from continuing operations, net of income taxes:
Three Months Ended September 30,(Decrease) Increase to IncomeNine Months Ended September 30,(Decrease) Increase to Income
 20242023$%20242023$%
 (Dollars in millions) (Dollars in millions)
Adjusted EBITDA (1)
$224.8 $270.0 $(45.2)(17)%$695.0 $1,018.8 $(323.8)(32)%
Depreciation, depletion and amortization(84.7)(82.3)(2.4)(3)%(247.4)(239.2)(8.2)(3)%
Asset retirement obligation expenses(12.9)(15.4)2.5 16 %(38.7)(46.3)7.6 16 %
Restructuring charges(1.9)(0.9)(1.0)(111)%(2.1)(3.0)0.9 30 %
Asset impairment— — — n.m.— (2.0)2.0 100 %
Provision for NARM and Shoal Creek losses— (3.3)3.3 100 %(3.7)(37.0)33.3 90 %
Shoal Creek insurance recovery - property damage— — — n.m.28.7 — 28.7 n.m.
Changes in amortization of basis difference related to equity affiliates0.4 0.5 (0.1)(20)%1.1 1.2 (0.1)(8)%
Interest expense, net of capitalized interest(9.7)(13.8)4.1 30 %(35.1)(45.5)10.4 23 %
Net loss on early debt extinguishment— — — n.m.— (8.8)8.8 100 %
Interest income17.7 20.3 (2.6)(13)%53.7 56.5 (2.8)(5)%
Unrealized gains on derivative contracts related to forecasted sales
— — — n.m.— 159.0 (159.0)(100)%
Unrealized gains (losses) on foreign currency option contracts3.7 (0.5)4.2 840 %0.4 0.1 0.3 300 %
Take-or-pay contract-based intangible recognition0.8 0.7 0.1 14 %2.3 1.9 0.4 21 %
Income tax provision(25.7)(46.5)20.8 45 %(85.2)(238.7)153.5 64 %
Income from continuing operations, net of income taxes$112.5 $128.8 $(16.3)(13)%$369.0 $617.0 $(248.0)(40)%
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:
Three Months Ended September 30,(Decrease) Increase to IncomeNine Months Ended September 30,(Decrease) Increase to Income
20242023$%20242023$%
 (Dollars in millions)(Dollars in millions)
Seaborne Thermal$(33.4)$(26.1)$(7.3)(28)%$(89.7)$(77.5)$(12.2)(16)%
Seaborne Metallurgical(19.5)(23.1)3.6 16 %(64.2)(67.1)2.9 4 %
Powder River Basin(14.6)(13.3)(1.3)(10)%(39.9)(35.6)(4.3)(12)%
Other U.S. Thermal(16.3)(17.9)1.6 9 %(46.9)(52.7)5.8 11 %
Corporate and Other
(0.9)(1.9)1.0 53 %(6.7)(6.3)(0.4)(6)%
Total$(84.7)$(82.3)$(2.4)(3)%$(247.4)$(239.2)$(8.2)(3)%

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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 operating segments:
Three Months Ended September 30,Nine Months Ended September 30,
 2024202320242023
Seaborne Thermal$2.18 $2.14 $2.12 $2.13 
Seaborne Metallurgical1.68 2.29 2.30 2.06 
Powder River Basin0.33 0.31 0.35 0.31 
Other U.S. Thermal1.55 1.23 1.59 1.25 
The changes in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the three and nine months ended September 30, 2024 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segments.
Provision for NARM and Shoal Creek Losses. The provision recorded during the prior year periods was for losses related to the events at the NARM and Shoal Creek Mines, as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements. Incremental repair costs related to the tornado damage at NARM were recorded during the current year.
Shoal Creek Insurance Recovery - Property Damage. During June 2024, the Company reached a settlement with its insurers and various re-insurers related to the Shoal Creek losses and recorded a $109.5 million insurance recovery, as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery, which consisted of $28.7 million recognized during the year ended December 31, 2023. The remaining $80.8 million, applicable to incremental costs and business interruption recoveries, is included in Adjusted EBITDA for the nine months ended September 30, 2024.
Interest Expense, Net of Capitalized Interest. The decrease in expense during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was driven by lower interest and fees for financial assurance instruments and the capitalization of interest related to the redevelopment of the Centurion Mine.
Net Loss on Early Debt Extinguishment. The loss recognized during the prior year was primarily related to the Company’s terminated letter of credit facility as further discussed in Note 12. “Financial Instruments and Other Guarantees” to the accompanying unaudited condensed consolidated financial statements.
Unrealized Gains on Derivative Contracts Related to Forecasted Sales. The prior year unrealized gains primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales. As further described in Note 6. "Derivatives and Fair Value Measurements" to the Annual Report on Form 10-K for the year ended December 31, 2023, all derivative contracts related to forecasted coal sales settled in 2023.
Income Tax Provision. The decrease in the income tax provision during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.

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Net Income Attributable to Common Stockholders
The following table presents net income attributable to common stockholders:
Three Months Ended September 30,Decrease
to Income		Nine Months Ended September 30,Decrease
to Income
20242023$%20242023$%
 (Dollars in millions)(Dollars in millions)
Income from continuing operations, net of income taxes$112.5 $128.8 $(16.3)(13)%$369.0 $617.0 $(248.0)(40)%
(Loss) income from discontinued operations, net of income taxes(1.0)2.5 (3.5)(140)%(3.3)(0.1)(3.2)(3,200)%
Net income111.5 131.3 (19.8)(15)%365.7 616.9 (251.2)(41)%
Less: Net income attributable to noncontrolling interests10.2 11.4 (1.2)(11)%25.4 49.3 (23.9)(48)%
Net income attributable to common stockholders$101.3 $119.9 $(18.6)(16)%$340.3 $567.6 $(227.3)(40)%
(Loss) Income from Discontinued Operations, Net of Income Taxes. The decrease in the results from discontinued operations, net of income taxes during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was primarily due to the prior year gain recognized on the settlement of the Patriot federal black lung liabilities.
Net Income Attributable to Noncontrolling Interests. The decrease in the results attributable to noncontrolling interests during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.
Diluted Earnings per Share (EPS)
The following table presents diluted EPS:
Three Months Ended September 30,Decrease
to EPS		Nine Months Ended September 30,Decrease
to EPS
 20242023$%20242023$%
Diluted EPS attributable to common stockholders:
Income from continuing operations$0.74 $0.80 $(0.06)(8)%$2.47 $3.68 $(1.21)(33)%
(Loss) income from discontinued operations— 0.02 (0.02)(100)%(0.03)— (0.03)n.m.
Net income attributable to common stockholders$0.74 $0.82 $(0.08)(10)%$2.44 $3.68 $(1.24)(34)%
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 141.6 million and 149.9 million for the three months ended September 30, 2024 and 2023, respectively, and 143.1 million and 156.7 million for the nine months ended September 30, 2024 and 2023, respectively.

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Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below.
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Income from continuing operations, net of income taxes$112.5 $128.8 $369.0 $617.0 
Depreciation, depletion and amortization
84.7 82.3 247.4 239.2 
Asset retirement obligation expenses
12.9 15.4 38.7 46.3 
Restructuring charges
1.9 0.9 2.1 3.0 
Asset impairment
— — — 2.0 
Provision for NARM and Shoal Creek losses— 3.3 3.7 37.0 
Shoal Creek insurance recovery - property damage— — (28.7)— 
Changes in amortization of basis difference related to equity affiliates(0.4)(0.5)(1.1)(1.2)
Interest expense, net of capitalized interest9.7 13.8 35.1 45.5 
Net loss on early debt extinguishment— — — 8.8 
Interest income
(17.7)(20.3)(53.7)(56.5)
Unrealized gains on derivative contracts related to forecasted sales— — — (159.0)
Unrealized (gains) losses on foreign currency option contracts(3.7)0.5 (0.4)(0.1)
Take-or-pay contract-based intangible recognition
(0.8)(0.7)(2.3)(1.9)
Income tax provision25.7 46.5 85.2 238.7 
Total Adjusted EBITDA
$224.8 $270.0 $695.0 $1,018.8 
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 September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Operating costs and expenses
$845.8 $803.7 $2,463.9 $2,512.3 
Unrealized gains (losses) on foreign currency option contracts3.7 (0.5)0.4 0.1 
Take-or-pay contract-based intangible recognition
0.8 0.7 2.3 1.9 
Net periodic benefit credit, excluding service cost(10.1)(10.0)(30.4)(29.4)
Total Reporting Segment Costs$840.2 $793.9 $2,436.2 $2,484.9 

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The following table presents Total Reporting Segment Costs by reporting segment:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
 (Dollars in millions)
Seaborne Thermal$193.2 $181.9 $586.4 $566.4 
Seaborne Metallurgical214.7 168.4 644.9 636.0 
Powder River Basin253.6 258.9 695.4 761.9 
Other U.S. Thermal188.3 179.1 500.0 512.3 
Corporate and Other(9.6)5.6 9.5 8.3 
Total Reporting Segment Costs$840.2 $793.9 $2,436.2 $2,484.9 
Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment (excluding insurance recoveries), 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, Total Reporting Segment Costs and Adjusted EBITDA by operating segment:
Three Months Ended September 30, 2024
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold4.1 1.7 22.1 4.0 
Revenue$313.2 $242.5 $305.3 $216.7 
Total Reporting Segment Costs193.2 214.7 253.6 188.3 
Adjusted EBITDA$120.0 $27.8 $51.7 $28.4 
Revenue per Ton$76.21 $144.60 $13.84 $53.52 
Costs per Ton47.01 128.04 11.50 46.50 
Adjusted EBITDA Margin per Ton$29.20 $16.56 $2.34 $7.02 
Three Months Ended September 30, 2023
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold4.2 1.5 22.7 4.2 
Revenue$297.4 $247.0 $313.0 $228.2 
Total Reporting Segment Costs181.9 168.4 258.9 179.1 
Adjusted EBITDA$115.5 $78.6 $54.1 $49.1 
Revenue per Ton$71.38 $162.02 $13.79 $53.89 
Costs per Ton43.68 110.38 11.41 42.28 
Adjusted EBITDA Margin per Ton$27.70 $51.64 $2.38 $11.61 

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Nine Months Ended September 30, 2024
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold12.2 5.1 56.6 10.9 
Revenue$904.6 $783.8 $781.3 $610.3 
Total Reporting Segment Costs586.4 644.9 695.4 500.0 
Adjusted EBITDA, excluding Shoal Creek insurance recovery$318.2 $138.9 $85.9 $110.3 
Shoal Creek insurance recovery - business interruption— 80.8 — — 
Adjusted EBITDA$318.2 $219.7 $85.9 $110.3 
Revenue per Ton$73.99 $154.31 $13.82 $55.92 
Costs per Ton47.96 126.98 12.30 45.81 
Adjusted EBITDA Margin per Ton$26.03 $27.33 $1.52 $10.11 
Nine Months Ended September 30, 2023
Seaborne ThermalSeaborne MetallurgicalPowder River BasinOther U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold11.8 4.8 63.6 12.5 
Revenue$1,043.4 $907.9 $878.0 $677.5 
Total Reporting Segment Costs566.4 636.0 761.9 512.3 
Adjusted EBITDA$477.0 $271.9 $116.1 $165.2 
Revenue per Ton$89.06 $189.50 $13.80 $54.12 
Costs per Ton48.35 132.74 11.98 40.92 
Adjusted EBITDA Margin per Ton$40.71 $56.76 $1.82 $13.20 
Available Free Cash Flow is defined as operating cash flow less investing cash flow and distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral and other anticipated expenditures. See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S. GAAP.
Nine Months Ended September 30, 2024
(Dollars in millions)
Net cash provided by operating activities$486.7 
 - Net cash used in investing activities(389.6)
 - Distributions to noncontrolling interests(34.8)
 +/- Changes to restricted cash and collateral(24.7)
 - Anticipated expenditures or other requirements— 
Available Free Cash Flow$37.6 
Regulatory Update
Other than as described in the following section, there were no significant changes to the Company’s regulatory or global climate matters subsequent to December 31, 2023. This section should be considered in connection with the Company’s regulatory and global climate matters as outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2023.

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Regulatory Matters - U.S.
National Ambient Air Quality Standards (NAAQS). The Clean Air Act (CAA) requires the U.S. Environmental Protection Agency (EPA) to review national ambient air quality standards every five years to determine whether revisions to current standards are appropriate. On March 6, 2024, the EPA revised the level of the primary standard for fine particulate matter (PM 2.5), lowering the annual standard from 12.0 ug/m3 to 9.0 ug/m3. States are now required to take several actions to implement the standards which could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies or operate in a different manner. Such actions could potentially increase the cost of utilizing fossil fuels for electric generation and industrial uses.
The EPA is also in the process of reviewing the current ozone NAAQS. The level of the ozone NAAQS can also affect requirements to install new or improved emission control technologies at fossil fuel-fired EGUs and non-EGU industrial sources.
Final New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs. The EPA promulgated a final rule to limit carbon dioxide (CO2) from new, modified and reconstructed fossil fuel-fired EGUs under Section 111(b) of the CAA on August 3, 2015, and published it in the Federal Register on October 23, 2015.
The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit.
Numerous legal challenges to the final rule were filed in the U.S. Court of Appeals for the District of Columbia (D.C. Circuit). Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.
On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs. In contrast to the 2018 proposed rule, the 2023 proposed rule did not propose to amend the 2015 NSPS for coal-fired EGUs. Status reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule. As indicated in the following section, on May 9, 2024, the EPA published the final rule in the Federal Register based on the 2023 proposed rule. This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future.
EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs. On May 9, 2024, the EPA published a final rule for new, modified and reconstructed fossil fuel-fired EGUs in the Federal Register. The final rule consists of four elements: (1) revised NSPS for controlling CO2 emissions from new and reconstructed stationary combustion turbines; (2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification; (3) emission guidelines for existing fossil fuel-fired steam EGUs; and (4) repeal of the Affordable Clean Energy rule promulgated in 2019.

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With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO2 emissions. Pursuant to the final rule, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO2 emission rate based on CCS with 90% capture by January 1, 2032. Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030. (This translates into a 16% reduction in CO2 emissions determined from a unit-specific baseline). Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements.
All requirements related to existing affected units in the final rule – whether fired by coal or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls. Under the final rule, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations. States are also permitted to impose more stringent standards. In addition, the final rule includes several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order to maintain adequate electric generation resources and grid reliability.
Finally, as part of the final rule, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU. In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032. Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015.
The final rule is subject to numerous legal challenges that have been consolidated in the D.C. Circuit. Petitioners filed an emergency application for a stay of the rule with the U.S. Supreme Court which was denied in an order issued by the U.S. Supreme Court on October 16, 2024. In a statement respecting this denial, Justices Kavanaugh and Gorsuch expressed the view that the petitioners “have shown a strong likelihood of success on the merits as to at least some of their challenges” but because efforts to comply would not need to be initiated until June 2025, they would be “unlikely to suffer irreparable harm before the Court of Appeals for the D.C. Circuit decides the merits” of the pending litigation. Justice Thomas would have granted the application for a stay; the views of other Justices regarding the merits of the litigation are unknown. If the rule is ultimately affirmed and implemented by the EPA and states, it could have a substantial impact on the use of coal and natural gas for the generation of electricity.
Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. In 2020, the EPA finalized revisions to certain requirements in the 2015 rule. On May 9, 2024, the EPA published a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule is subject to numerous legal challenges that have been consolidated in the Eighth Circuit. If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034.
Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2024. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. On May 8, 2024, the EPA published a final rule containing additional amendments to the 2015 CCR rule that further address aspects of the D.C. Circuit’s 2018 decision. Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units.
Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. The CSAPR and related updates require numerous U.S. states and the District of Columbia to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine PM pollution in other states.

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On March 15, 2023, the EPA issued a final rule to address regional ozone transport by imposing new federal ozone season emission budgets for nitrogen oxide (NOx) in 23 states, including California, Nevada, Oklahoma and Texas, as well as some Indian reservations. The rule includes state emission budgets for NOx affecting fossil fuel-fired power plants and a “backstop daily emissions rate” for large coal-fired power plants if they exceed specified limits. The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states. The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million. 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. When implemented, this rule could influence the closure of some coal generating units that have not installed selective catalytic reduction technologies.
Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S. Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others. On June 27, 2024, the U.S. Supreme Court issued a stay of the rule in 11 states pending the disposition of a petition for review of the rule in the D.C. Circuit and any subsequent timely petition for certiorari filed with and granted by the U.S. Supreme Court. The EPA subsequently issued a policy memorandum on August 5, 2024, that provides an administrative stay of the rule; the D.C. Circuit thereafter issued a partial remand of the rule to allow the EPA to respond to comments regarding the severability of the rule’s provisions.
Mercury and Air Toxic Standards (MATS). In 2012, the EPA published the final MATS rule, which revised the NSPS for NOx, sulfur dioxide 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.
On March 6, 2023, the EPA issued a final rule which reaffirmed its determination to regulate coal- and oil-fired EGUs under CAA section 112, including the regulation of HAPs from EGUs after considering cost. On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%. On April 25, 2024, the EPA issued its final MATS rule which significantly tightens the filterable particulate matter (fPM) emissions limit for existing coal-fired EGU’s, lowering the standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu.
Regional Haze. The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from man-made air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years. On March 29, 2024, the EPA published a proposed consent decree under which deadlines would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026). The EPA subsequently filed a motion to approve the consent judgement in the U.S. District Court for the District of Columbia which was granted.
Federal Coal Leasing Moratorium. The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the court held that the Department of Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. On appeal, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349. The Ninth Circuit directed the district court to dismiss the case as moot.

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Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the Trump Administration, the Departments of Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, the agencies announced their plan to revise, rescind or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The agencies issued proposed rules on June 22, 2023, and they published three final revised rules on April 5, 2024.
SEC Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules pending such judicial review. The Company is assessing the potential impact of the final rules.
Regulatory Matters - Australia
Coal Mine Subsidence Compensation Amendment Act 2024 (NSW). On August 15, 2024, the Coal Mine Subsidence Compensation Amendment Act 2024 No. 48 (NSW) was passed into law. The amendment act amends the Coal Mine Subsidence Compensation Act 2017 No. 37 (NSW), implementing all nine recommendations of the 2023 statutory review. The amendments are designed to strengthen the compensation framework to ensure people affected by coal mine subsidence in New South Wales (NSW) can access compensation and support. The key amendments include extension of the chief executive’s powers to evacuate people from land they reasonably believe has been damaged as a result of subsidence and that may cause danger to a member of the public; make payment from the fund for temporary accommodation for people who have been evacuated; requirement of the Subsidence Advisory to assess claims as soon as reasonably practicable after receiving a compensation claim; limitation on claims if pre-mining inspection was required and refused by the claimant and addition of powers to direct pre-mining inspections; requiring information and documents from coalmine operators; and clarifying the roles of Subsidence Advisory and mine operators in the assessment and determination of claims.
Work Health and Safety Act 2011 (NSW). On June 4, 2024, the Work Health and Safety Amendment (Industrial Manslaughter) Bill 2024 (Bill) was introduced to the NSW Parliament. The Bill subsequently passed the NSW Parliament on June 20, 2024. The Bill amends the Work Health and Safety Act 2011 (NSW) (NSW WHS Act) to include the offense of industrial manslaughter. The offense will apply to a person conducting a business or undertaking (PCBU) or an officer of a PCBU who engages in conduct that constitutes a failure to comply with the person’s health and safety duty and causes the death of a worker or another individual to whom the duty is owed; and the person engages in conduct with gross negligence. The maximum penalty is $20 million Australian dollars for a body corporate or 25 years imprisonment for an individual. The Bill also provides for an alternative finding of guilt. That is, where a person is charged with industrial manslaughter, and on trial the court or jury is not satisfied that the person is guilty but is satisfied that the person is guilty of an offense against section 31 (Gross negligence or reckless conduct— Category 1) of the NSW WHS Act, the person may be found guilty and liable to punishment for that offense.
Environmental Protection (Powers and Penalties) and Other Legislation Amendment Act 2024 (QLD) (Powers and Penalties Act). On June 18, 2024, the Environmental Protection (Powers and Penalties) and Other Legislation Amendment Act 2024 (QLD) (Powers and Penalties Act) received assent. The Powers and Penalties Act amends the powers and penalties provisions of the Environmental Protection Act 1994 (EP Act), facilitates a more proactive approach to environmental risk management and ensures timely and effective regulatory responses to environmental harm. The key changes include the general environmental duty becoming an offense provision, an increase in maximum penalties and the consolidation of the various enforcement instruments presently available under the EP Act into a single Environmental Enforcement Order.

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National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the NGER Act. The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review. In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015. The reforms commenced on July 1, 2023 and introduced site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO2 in 2023-24, increasing with the Consumer Price Index plus 2% each year. In June 2024 amendments to the NGER Act came into effect requiring open-cut mines covered by the Safeguard Mechanism that currently report fugitive methane emissions using a basic method with minimal data inputs (Method 1) to transition over a two-year period to a more complex method requiring site-level sampling and analysis (Methods 2 or 3). This change in reporting methods is expected to increase the Safeguard Mechanism liability position of open-cut mining operations in Queensland. The impacts of this change are currently being assessed.
New South Wales Environmental. Under the NSW Environmental Planning and Assessment Act 1979 (EPA Act), environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve.
On April 3, 2024, the Environment Protection Legislation Amendment (Stronger Regulation and Penalties) Bill 2024 was assented to by the Parliament of New South Wales. The bill increases the NSW Environment Protection Agency’s (NSW EPA) powers across a range of environmental legislation including increasing the NSW EPA’s maximum penalties for serious environmental offenses; increasing the NSW EPA’s on-the-spot maximum fines; providing the NSW EPA the power to issue what will be known as ‘Preliminary Investigation Notices’ which permit the NSW EPA to force a person to help the NSW EPA compile a criminal case against the person or against another person; extending the monetary benefits order so that it can apply to any ‘related entity’ as defined in the Corporations Act 2001; providing the NSW EPA the power to issue what will be known as ‘Recall Notices’ which order responsible entities to recall contaminated substances suspected of causing harm to the community and environment; and providing the NSW EPA the power to issue what will be known as ‘name and shame’ public warnings to call out poor and repeat environmental performers for the protection of communities. The reform also creates a new power in Australia for the NSW Land and Environment Court that empowers the court to ban offenders, upon the NSW EPA’s application, with a poor compliance history from seeking and obtaining environmental protection licenses.
On August 25, 2017, the Biodiversity Conservation Act 2016 (BC Act) commenced in NSW and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied. On July 18, 2024, following an independent review of the BC Act, the NSW government announced it would amend the BC Act to reform the biodiversity offsets scheme. On August 13, 2024, the Biodiversity Conservation Amendment (Biodiversity Offsets Scheme) Bill 2024 was introduced into NSW Parliament and, if passed into law, will require mining proponents to demonstrate they have genuinely avoided, minimized and offset impacts to biodiversity. The bill reinforces the current government’s intent that biodiversity offsets are a last resort. Additionally, the bill proposes to replace the current ‘no net loss’ standard for biodiversity with the requirement for proponents to achieve ‘net positive’ biodiversity outcomes. If enacted, these and other proposed changes have the potential to affect approval processes for future NSW mining projects. NSW Parliament is expected to pass the bill by late November 2024.

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New South Wales Coal Directions. The State of New South Wales enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing. Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which were amended at various dates. The most recent directions required Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and imposed additional reporting obligations to demonstrate compliance. The Australian Energy Regulator has confirmed that the directions have ended, and the last report was submitted on July 12, 2024.
Aboriginal and Torres Strait Islander Heritage Protection Act 1984. On August 16, 2024, Australia’s Minister for the Environment and Water made a declaration under Section 10 of the Aboriginal and Torres Strait Islander Heritage Protection Act 1984 over a riverine area in NSW that is a proposed tailings dam site for a gold mining project. The declaration prohibits any mining or related development activity in the area despite the project having previously obtained all necessary environmental and planning approvals under state and federal government laws. The project proponent has indicated that the decision renders the mine project as no longer financially viable given the time required to develop and receive approvals for an alternative tailings dam site. The decision has the potential to affect future mining approvals in Australia. The proponent has until early November to apply for a judicial review of the minister’s decision.
Risks Related to Global Climate Change
There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2023. Refer to Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 for information regarding the Company’s global climate matters.
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, coal resources 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, finance and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, dividends, share repurchases and selling and administrative expenses. The Company has also used cash for early debt retirements.
Any future determinations to return capital to stockholders, such as dividends or share repurchases, will depend on a variety of factors, including the Company’s 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.
Liquidity
As of September 30, 2024, the Company’s cash and cash equivalents balances totaled $772.9 million, including approximately $420 million held by U.S. subsidiaries, approximately $336 million held by Australian subsidiaries and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by the Company’s foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia and payment of the foreign subsidiaries’ share of certain U.S. corporate expenditures. From time to time, the Company may repatriate profits from its foreign subsidiaries to the U.S. in the form of intercompany dividends. During the nine months ended September 30, 2024, no profits from foreign subsidiaries were repatriated. If 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.

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The Company’s available liquidity increased to $1,089.9 million as of September 30, 2024 from $1,059.7 million as of December 31, 2023. Available liquidity was comprised of the following:
September 30, 2024December 31, 2023
(Dollars in millions)
Cash and cash equivalents$772.9 $969.3 
Revolving credit facility availability221.4 — 
Accounts receivable securitization program availability95.6 90.4 
Total liquidity$1,089.9 $1,059.7 
Capital Returns to Shareholders
The Company repurchased approximately 7.7 million shares of its common stock for $180.5 million, including commission fees, and paid dividends of $28.5 million during the nine months ended September 30, 2024.
Surety Agreement Amendment and Collateral Requirements
In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the April 2023 amendment, the Company and its surety providers agreed to a maximum aggregate collateral amount of $721.8 million based upon bonding levels at the effective date of the amendment. This maximum collateral amount will vary prospectively as bonding levels increase or decrease. The amendment extended the agreement through December 31, 2026. In order to maintain the maximum collateral agreement, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers, which was $507.3 million at September 30, 2024. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company’s 3.250% Convertible Senior Notes due March 2028 (the 2028 Convertible Notes) is deemed to be funded debt. The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. The Company is in compliance with such requirements at September 30, 2024.
To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023. The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider. The amendment became effective on April 14, 2023, when the Company terminated a then-existing credit agreement.
Credit Support Facilities
In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to 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 variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At September 30, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million.
In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. The Company receives a variable deposit rate on the amount of cash collateral posted in support of the bank guarantee facilities, which mature at various dates between 2026 and 2029. At September 30, 2024, the bank guarantee facilities were backed by cash of $187.9 million.
Revolving Credit Facility
The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto.

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The revolving commitments and any related loans, if applicable (any such loans, the Revolving Loans), established by the 2024 Credit Agreement terminate or mature, as applicable, on January 18, 2028, subject to certain conditions relating to the Company’s outstanding 2028 Convertible Notes. The Revolving Loans bear interest at a secured overnight financing rate (SOFR) plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option. Letters of credit issued under the 2024 Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.50% to 4.25% plus a fronting fee equal to 0.125% per annum. Unused capacity under the 2024 Credit Agreement bears a commitment fee of 0.50% per annum.
As of September 30, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $98.6 million outstanding as of September 30, 2024. These letters of credit support the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees as further described in Note 12. “Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $221.4 million at September 30, 2024.
The 2024 Credit Agreement contains customary covenants that, among other things and subject to certain exceptions (including compliance with financial ratios), may limit the Company and its subsidiaries’ ability to incur additional indebtedness, make certain restricted payments or investments, sell or otherwise dispose of assets, enter into transactions with affiliates, create or incur liens, and merge, consolidate or sell all or substantially all of their assets. The 2024 Credit Agreement is secured by substantially all assets of the Company and its U.S. subsidiaries, as well as a pledge of two Australian subsidiaries.
Capital Expenditures
The Company increased its targeted capital expenditures for 2024 from approximately $375 million to $425 million. The increase is primarily driven by the acceleration of the planned capital spend at the Centurion Mine as development rates have advanced ahead of projected timelines and timing of spend at the Wambo Open-Cut Mine.
Indebtedness
The Company’s total indebtedness as of September 30, 2024 and December 31, 2023 is presented in the table below.
Debt Instrument (defined below, as applicable)September 30, 2024December 31, 2023
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes)$320.0 $320.0 
Finance lease obligations25.1 22.3 
Less: Debt issuance costs(6.6)(8.1)
338.5 334.2 
Less: Current portion of long-term debt14.8 13.5 
Long-term debt$323.7 $320.7 
The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at September 30, 2024, of approximately $8 million in 2024, $20 million in 2025, $17 million in 2026, $13 million in 2027 and $326 million in 2028.
Cash paid for interest, net of capitalized interest related to the Company’s indebtedness and financial assurance instruments amounted to $32.6 million and $56.7 million during the nine months ended September 30, 2024 and 2023, respectively.
2028 Convertible Notes
On March 1, 2022, through a private offering, the Company issued the 2028 Convertible Notes in the aggregate principal amount of $320.0 million. 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 and available cash to redeem its then-existing senior secured notes, and to pay related premiums, fees and expenses relating to the offering and redemptions.

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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 bear interest at a rate of 3.250% per year, payable semi-annually in arrears on March 1 and September 1 of each year.
During the first three quarters of 2024, the Company’s reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes were not convertible at the option of the holders during the second or third quarters of 2024, and will not be similarly convertible during the fourth quarter of 2024.
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 February 2023 to increase the available funding capacity from $175.0 million to $225.0 million and adjust the relevant interest rate for borrowings to a SOFR plus an applicable margin. 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, which has been the Company’s primary utilization. At September 30, 2024, the Company had no outstanding borrowings and $60.4 million of letters of credit outstanding under the program. The Company was not required to post cash collateral under the securitization program at September 30, 2024.
Covenant Compliance
The Company was compliant with all relevant covenants under its debt and other finance agreements at September 30, 2024.
Cash Flows
The following table summarizes the Company’s cash flows for the nine months ended September 30, 2024 and 2023, as reported in the accompanying unaudited condensed consolidated financial statements. Available Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Nine Months Ended September 30,
20242023
 (Dollars in millions)
Net cash provided by operating activities$486.7 $753.1 
Net cash used in investing activities(389.6)(174.6)
Net cash used in financing activities(268.8)(364.5)
Net change in cash, cash equivalents and restricted cash(171.7)214.0 
Cash, cash equivalents and restricted cash at beginning of period1,650.2 1,417.6 
Cash, cash equivalents and restricted cash at end of period$1,478.5 $1,631.6 
Available Free Cash Flow$37.6 
Operating Activities. The decrease in net cash provided by operating activities for the nine months ended September 30, 2024 compared to the same period in the prior year was driven by a year-over-year decrease in operating cash flow from working capital ($260.9 million), primarily attributable to income tax payments and accruals ($218.8 million) and Shoal Creek inventories build due to the lock outages during 2024 ($61.1 million); the prior year receipt of cash related to variation margin requirements associated with derivative financial instruments ($198.0 million); and lower cash generated from mining operations. These unfavorable variances were partially offset by decreases in cash used for collateral requirements ($289.2 million) and discontinued operations ($74.9 million) primarily related to the prior year use of cash to settle disputed black lung claims.
Investing Activities. The increase in net cash used in investing activities for the nine months ended September 30, 2024 compared to the same period in the prior year was driven by the acquisition of Wards Well ($143.8 million) and higher capital expenditures ($75.3 million).

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Financing Activities. The decrease in net cash used by financing activities for the nine months ended September 30, 2024 compared to the same period in the prior year was primarily driven by decreases in common stock repurchases ($80.9 million) and distributions to noncontrolling interest ($24.1 million), partially offset by an increase in payment of debt issuance and other deferred financing costs ($10.8 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. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance 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 the accompanying condensed consolidated balance sheets.
The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.
 September 30, 2024
 Reclamation Support
Other Support (1)
Total
 (Dollars in millions)
Surety bonds$932.2 $107.7 $1,039.9 
Letters of credit (2)
55.2 103.8 159.0 
987.4 211.5 1,198.9 
Less: Letters of credit in support of surety bonds (3)
(55.2)(12.4)(67.6)
Obligations supported, net$932.2 $199.1 $1,131.3 
(1)    Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.
(2)    Amounts do not include cash-collateralized letters of credit.
(3)    Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers.
Not presented in the above table is $839.0 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at September 30, 2024, as described in Note 12. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements. Such collateral is primarily in support of the financial instruments noted above, including in relation to the Company’s surety bond portfolio, its collateralized letter of credit agreement, its bank guarantee facilities and amounts held directly with beneficiaries which are not supported by surety bonds. The restricted cash and collateral balance decreased $118.6 million during the nine months ended September 30, 2024 due to collateral releases related to reductions in reclamation bonding requirements, replacement of cash-collateralized letters of credit with letters of credit under the new revolving credit facility and the impact of foreign currency rate changes.
At September 30, 2024, the Company had total asset retirement obligations of $701.4 million. Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas 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.
As noted above, the Company’s reclamation bonding requirements decreased during the nine months ended September 30, 2024, primarily due to an approximate $110 million reduction in U.S. reclamation bonding requirements. At September 30, 2024, the Company’s reclamation bonding requirements were supported by approximately $725 million of restricted cash and other balances serving as collateral, which exceeds the financial liability for final mine reclamation as calculated in accordance with U.S. GAAP.

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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.
At September 30, 2024, the Company identified certain assets with an aggregate carrying value of approximately $207 million in its Other U.S. Thermal segment whose recoverability is most sensitive to customer concentration risk.
The Company’s critical accounting policies and estimates are discussed in Part II, 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, 2023. The Company’s critical accounting policies remain unchanged at September 30, 2024, 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.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Coal Pricing Risk
The Company predominantly manages its commodity price risk for its non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year) to the extent possible, rather than through the use of derivative instruments. As of September 30, 2024, the Company had approximately 100 million tons of U.S. thermal coal priced and committed for 2024. This includes approximately 85 million tons of PRB coal and 15 million tons of other U.S. thermal coal. The Company has the flexibility to increase volumes should demand warrant. Peabody is estimating full year 2024 thermal coal sales volumes from its Seaborne Thermal segment of 16.0 million to 16.4 million tons comprised of thermal export volume of 10.0 million to 10.4 million tons and domestic volume of 6.0 million tons. Peabody is estimating full year 2024 metallurgical coal sales from its Seaborne Metallurgical segment of 7.2 million to 7.6 million tons. Sales commitments in the metallurgical coal market are typically not long-term in nature, and the Company is therefore subject to fluctuations in market pricing. The Company’s sensitivity to market pricing in thermal coal markets is dependent on the duration of contracts.
As of September 30, 2024, the Company had no coal derivative contracts related to its forecasted sales. Historically, such financial contracts have included futures and forwards.
Foreign Currency Risk
The Company utilizes options and collars to hedge currency risk associated with anticipated Australian dollar operating expenditures. The accounting for these derivatives is discussed in Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. As of September 30, 2024, the Company held average rate options with an aggregate notional amount of $531.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar operating expenditures over the nine-month period ending June 30, 2025. As of September 30, 2024, the Company also held purchased collars with an aggregate notional amount of $468.0 million Australian dollars related to anticipated Australian dollar operating expenditures during the nine-month period ending June 30, 2025. Assuming the Company had no foreign currency hedging instruments in place, its exposure in operating costs and expenses due to a $0.10 change in the Australian dollar/U.S. dollar exchange rate is approximately $205 million to $215 million for the next twelve months. Based upon the Australian dollar/U.S. dollar exchange rate at September 30, 2024, the currency option contracts outstanding at that date would limit the Company’s exposure to approximately $127 million with respect to a $0.10 increase in the exchange rate, while the Company would benefit by approximately $198 million with respect to a $0.10 decrease in the exchange rate for the next twelve months.

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Although Peabody believes its Australian dollar monetary asset position acts as a hedge to lessen the impact on its results from operations, the Company may continue to use options and collars to hedge its cash flow exposure to currency risk associated with anticipated Australian dollar operating expenditures.
Diesel Fuel Price Risk
The Company expects to consume 85 to 95 million gallons of diesel fuel during the next twelve months. A $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease its annual diesel fuel costs by approximately $21 million based on its expected usage.
As of September 30, 2024, the Company did not have any diesel fuel derivative instruments in place. The Company partially manages the price risk of diesel fuel through the use of cost pass-through contacts with certain customers.
Interest Rate Risk
Peabody’s objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. Peabody is primarily exposed to interest rate risk as a result of its interest-earning cash balances.
Peabody’s interest-earning cash and restricted cash balances are primarily held in deposit accounts and investments with maturities of three months or less. Therefore, these balances are subject to interest rate fluctuations and could produce less income if interest rates fall. Based upon its interest-earning cash and restricted cash balances at September 30, 2024, a one percentage point decrease in interest rates would result in a decrease of approximately $15 million to interest income for the next twelve months.
Item 4. Controls and Procedures.
The Company’s disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including its principal executive and financial officers, on a timely basis. The Company’s Chief Executive Officer and Chief Financial Officer have evaluated its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of September 30, 2024, and concluded that such controls and procedures were effective to provide reasonable assurance that the desired control objectives were achieved. Additionally, there have been no changes to the Company’s internal control over financial reporting during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
The Company is subject to various legal and regulatory proceedings. For a description of its significant legal proceedings refer to Note 13. “Commitments and Contingencies” to the unaudited condensed consolidated financial statements included in Part I, Item 1. “Financial Statements” of this Quarterly Report, which information is incorporated by reference herein.
Item 1A. Risk Factors.
The Company operates in a rapidly changing environment that involves a number of risks. For information regarding factors that could affect the Company’s results of operations, financial condition and liquidity, see the risk factors disclosed in Item 1A. “Risk Factors” of Part I of its Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 23, 2024 and Item 1A. “Risk Factors” of Part II of its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2024 filed with the SEC on August 8, 2024. In addition to the other information set forth in this Quarterly Report, including the information presented in Part I, Item 2. “Management's Discussion and Analysis of Financial Condition and Results of Operations,” you should carefully consider the risk factors disclosed in the aforementioned filings, which could materially affect the Company's results of operations, financial condition and liquidity.
Factors that could affect the Company’s results or an investment in the Company’s securities include, but are not limited to:
•the Company’s profitability depends upon the prices it receives for its coal;

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•if a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenue and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts;
•risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company;
•the Company’s take-or-pay arrangements could unfavorably affect its profitability;
•the Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets;
•the Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel;
•the Company could be negatively affected if it fails to maintain satisfactory labor relations;
•the Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations;
•if the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated;
•the Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal;
•the Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company;
•the Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability;
•concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators;
•numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company’s future financial results, liquidity and growth prospects;
•the Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks;
•the Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable;
•the Company faces numerous uncertainties in estimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenue, higher than expected costs and decreased profitability;
•joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards;
•the Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect;
•high inflation could continue to result in higher costs and decreased profitability;
•the Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by pandemic or other widespread illnesses and the related effects on public health;
•Peabody is exposed to risks associated with political or international conflicts;
•Peabody could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if it sustains cybersecurity attacks or other security breaches that disrupt its operations or result in the dissemination of proprietary or confidential information about the Company, its customers or other third-parties;
•Peabody’s information and operational technology systems have been and in the future may be adversely affected by disruptions, damage, failure and risks associated with implementation and integration, including of new technologies;
•the Company is subject to various general operating risks which may be fully or partially outside of its control;

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•the Company may be able to incur more debt, including secured debt, which could increase the risks associated with its indebtedness;
•the terms of the agreements and instruments governing the Company’s debt and surety bonding obligations impose restrictions that may limit its operating and financial flexibility;
•the number and quantity of viable financing and insurance alternatives available to the Company may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its securities from consideration by those investors;
•the price of Peabody’s securities may be volatile;
•Peabody’s common stock is subject to dilution and may be subject to further dilution in the future;
•there may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests;
•the future payment of dividends on Peabody’s stock or future repurchases of its stock is dependent on a number of factors and cannot be assured;
•the Company may not be able to fully utilize its deferred tax assets;
•acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits;
•Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt;
•diversity in interpretation and application of accounting literature in the mining industry may impact the Company’s reported financial results; and
•other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 of this Quarterly Report on Form 10-Q.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Share Repurchase Program
On April 17, 2023, the Company announced that its Board of Directors authorized a new share repurchase program (2023 Repurchase Program) authorizing repurchases of up to $1.0 billion of its common stock.
Under the 2023 Repurchase Program, the Company may purchase shares of common stock from time to time at the discretion of management through open market purchases, privately negotiated transactions, block trades, accelerated or other structured share repurchase programs or other means. The amount of any share repurchase transactions is subject to the Company’s annual AFCF. The manner, timing, and pricing of any share repurchase transactions will be based on a variety of factors, including market conditions, applicable legal requirements and alternative opportunities that the Company may have for the use or investment of capital. Through September 30, 2024, the Company had repurchased 23.8 million shares of its common stock under the 2023 Repurchase Program for $530.8 million, which included commissions paid of $0.4 million, leaving $469.6 million available for share repurchase.
Dividends
During the three and nine months ended September 30, 2024, the Company declared dividends per share of $0.075 and $0.225, respectively. On October 31, 2024, the Company declared an additional dividend per share of $0.075 to be paid on December 4, 2024 to shareholders of record as of November 14, 2024. The declaration and payment of dividends and the amount of dividends will depend on the Company’s annual AFCF.
Share Relinquishments
The Company routinely allows employees to relinquish Common Stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in Common Stock under its equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of the Company’s Common Stock on the dates of the respective relinquishments.

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Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended September 30, 2024:
Period
Total
Number of
Shares
Purchased (1)
Average
Price Paid per
Share		Total Number of
Shares Purchased
as Part of Publicly
Announced
Program		Maximum Dollar
Value that May
Yet Be Used to
Repurchase Shares
Under the Publicly
Announced Program
(In millions)
July 1 through July 31, 2024291 $23.26 — $569.6 
August 1 through August 31, 20241,057,013 22.50 1,057,013 545.8 
September 1 through September 30, 20243,374,598 22.56 3,374,598 469.6 
Total4,431,902 22.55 4,431,611  
(1)Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the publicly announced repurchase programs.
Item 4. Mine Safety Disclosures.
Peabody’s “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across the Company’s business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. Peabody also partners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve its safety performance and provide better safety protection for employees.
Peabody continually monitors its safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Quarterly Report on Form 10-Q.
Item 5. Other Information.
Securities Trading Plans of Directors and Executive Officers
During the three months ended September 30, 2024, none of Peabody’s directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K of the Exchange Act.
Item 6. Exhibits.
See Exhibit Index on following pages.

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EXHIBIT INDEX
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
Exhibit No.Description of Exhibit
31.1†
31.2†
32.1†
32.2†
95†
101.INSInline XBRL Instance Document - the instance document does not appear in the interactive data file because XBRL tags are embedded within the Inline XBRL document
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101.LABInline XBRL Taxonomy Extension Label Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (embedded within the Inline XBRL document).
†Filed herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEABODY ENERGY CORPORATION
Date:November 8, 2024By:/s/ MARK A. SPURBECK
Mark A. Spurbeck
Executive Vice President and Chief Financial Officer
(On behalf of the registrant and as Principal Financial Officer) 







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