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美国
证券交易委员会
华盛顿特区20549
表格 10-Q

（标记一）
☑根据第13或15(d)条规定的季度报告
证券交易所法案(1934年)
截至季度结束
2024年9月30日

or
☐根据第13条或第15条(d)的规定进行过渡报告
证券交易所法案(1934年)
对于从____________至____________的过渡期
委托文件编号：001-398661-16463
____________________________________________
peabodylogoa36.jpg
peabody energy 协会CORATION
(根据其章程规定的注册人准确名称)
特拉华州13-4004153
（设立或组织的其他管辖区域） （纳税人识别号码）
701 Market Street,圣路易斯密苏里州63101-1826
，（主要行政办公地址）(邮政编码)
(314) 342-3400
(注册人电话号码，包括区号)
在法案第12(b)条的规定下注册的证券：
每一类的名称交易标志在其上注册的交易所的名称
普通股，每股面值0.01美元英热单位。请使用moomoo账号登录查看New York Stock Exchange
请在以下空格内打勾，以表示注册人：(1)在过去12个月(或注册人所要求提交此类报告的更短期间内)已提交了根据1934年证券交易法第13或15(d)条规定需要提交的所有报告；并且(2)在过去90个天内一直遵守此类提交要求。Yes ☑  否 ☐
请使用复选标记指示，注册人是否在过去12个月（或注册人必须提交此类文件的较短期间）递交了根据S-t法规第405条规定需要递交的每个交互式数据文件。 Yes ☑  否 ☐
请勾选圆圈以表示公司的注册人是否为大型加速报告公司、加速报告公司、非加速报告公司、小型报告公司或新兴成长公司。有关“大型加速报告公司”、“加速报告公司”、“小型报告公司”和“新兴成长公司”的定义，请参见《交易所法规》第120亿.2条。
大型加速报告人 ☑                          加速报告人☐
非加速报告人☐                较小的报告公司 ☐
新兴增长型公司 ☐
如果是新兴成长型企业，请勾选复选标记，表明注册者已选择不使用延长过渡期来符合根据证券交易法第13(a)条规定提供的任何新财务会计准则。 ☐
请在以下方框内打勾：公司是否是空壳公司(根据证券交易法第12b-2条规定定义）。是☐ 否 ☑
截至2023年7月31日，续借贷款协议下未偿还的借款额为121.5 注册人的普通股（每股面值为0.01美元）于2024年11月4日持有的股份为百万股。


目录
 页面
 
 

目录


第一部分 - 财务信息
项目1.基本报表。
未经审计的基本财务报表综合损益表

截至9月30日的三个月截至9月30日的九个月内，
2024202320242023
（金额单位：百万美元，每股数据除外）
营业收入$1,088.0 $1,078.9 $3,113.6 $3,711.7 
费用和支出
净利润（不包括下列分项所示的数额）845.8 803.7 2,463.9 2,512.3 
折旧、减值和摊销84.7 82.3 247.4 239.2 
资产养老责任费用12.9 15.4 38.7 46.3 
销售及管理费用20.6 21.5 64.7 66.0 
重组费用1.9 0.9 2.1 3.0 
其他营业（收入）损失：
处置净利得(0.1)(1.4)(9.7)(8.5)
资产减值— — — 2.0 
为NARm和Shoal Creek损失提供准备金— 3.3 3.7 37.0 
Shoal Creek保险索赔— — (109.5)— 
股权联营公司损益（收益）2.1 (5.6)7.1 (9.7)
营业利润120.1 158.8 405.2 824.1 
利息支出，减去资本化利息9.7 13.8 35.1 45.5 
提前偿还债务产生的净损失— — — 8.8 
利息收入(17.7)(20.3)(53.7)(56.5)
除服务成本外的净周期性福利贷方(10.1)(10.0)(30.4)(29.4)
未来营业收入净额138.2 175.3 454.2 855.7 
所得税费用25.7 46.5 85.2 238.7 
扣除所得税后的持续经营活动收入112.5 128.8 369.0 617.0 
（损失）终止经营业务净收益（损失），净收益税后(1.0)2.5 (3.3)(0.1)
净利润111.5 131.3 365.7 616.9 
净利润归属于非控制权益10.2 11.4 25.4 49.3 
归属于普通股股东的净收益$101.3 $119.9 $340.3 $567.6 
持续经营收入：
每股基本收益$0.82 $0.88 $2.72 $4.06 
每股摊薄收益$0.74 $0.80 $2.47 $3.68 
归属于普通股股东的净利润：  
每股基本收益$0.81 $0.90 $2.69 $4.05 
每股摊薄收益$0.74 $0.82 $2.44 $3.68 
请参见附注的未经审计的简明合并财务报表。

1

目录


未经审计的简明综合收益表

截至9月30日的三个月截至9月30日的九个月内，
2024202320242023
(金额单位：百万美元)
净利润$111.5 $131.3 $365.7 $616.9 
养老金计划（净额为$0.0 每期税款准备金（税款净额在每期）
(13.3)(13.5)(39.8)(40.3)
外币翻译调整2.3 (1.0)0.9 (1.6)
其他全部损失，扣除所得税净额(11.0)(14.5)(38.9)(41.9)
综合收益100.5 116.8 326.8 575.0 
净利润归属于非控制权益10.2 11.4 25.4 49.3 
归属于普通股股东的综合收益$90.3 $105.4 $301.4 $525.7 
请参见附注的未经审计的简明合并财务报表。

2

目录


简明合并资产负债表
(未经审计)
2024年9月30日2023年12月31日
（金额单位为以百万计，每股数据除外）
资产  
流动资产  
现金及现金等价物$772.9 $969.3 
应收账款，减去2024年4月30日和2024年1月31日的信用损失准备，分别为 0.0 截至2024年9月30日和2023年12月31日
304.2 389.7 
净存货444.3 351.8 
其他资产286.6 308.9 
总流动资产1,808.0 2,019.7 
Property, plant, equipment and mine development, net3,013.5 2,844.1 
经营租赁权使用资产121.1 61.9 
Restricted cash and collateral839.0 957.6 
投资和其他资产85.3 78.8 
资产总额$5,866.9 $5,962.1 
负债和股东权益  
流动负债  
开多次数$14.8 $13.5 
应付账款和应计费用763.8 965.5 
流动负债合计778.6 979.0 
长期债务，减去当期部分323.7 320.7 
延迟所得税17.8 28.6 
资产退休义务，减少当前部分647.4 648.6 
退休后福利成本143.1 148.4 
租赁负债，除去当前部分94.6 47.7 
其他非流动负债171.3 181.6 
负债合计2,176.5 2,354.6 
股东权益  
优先股 — $0.01 每股面值； 100.0 no 2024年9月30日和2023年12月31日股份发行或已发行
— — 
普通股系列 — $0.01 每股帐面价值; 50.0 no 2024年9月30日和2023年12月31日股份发行或已发行
— — 
普通股 — $0.01 每股面值； 450.0 189.1股份发行量为121.4 截至2024年9月30日的流通股份达到 188.6股份发行量为128.7 2023年12月31日的股份总数
1.9 1.9 
额外实收资本3,988.9 3,983.0 
开多股票，以成本计量 — 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)
保留盈余1,424.3 1,112.7 
累计其他综合收益150.7 189.6 
peabody energy公司股东权益3,639.3 3,547.0 
非控制权益51.1 60.5 
股东权益总额3,690.4 3,607.5 
负债和股东权益总额$5,866.9 $5,962.1 
请参见附注的未经审计的简明合并财务报表。

3

目录


未经审计的现金流量综合表
截至9月30日的九个月
20242023
 (金额单位：百万美元)
经营活动现金流 
净利润$365.7 $616.9 
终止运营的损失，扣除所得税3.3 0.1 
扣除所得税后的持续经营活动收入369.0 617.0 
调整将持续经营收入（扣除所得税）与经营活动产生的净现金进行对账： 
折旧、衰减和摊销247.4 239.2 
非现金利息支出，净额4.0 4.0 
递延所得税(10.9)71.8 
Noncash share-based compensation5.7 5.1 
资产减值— 2.0 
非现金NARm和Shoal Creek损失的准备— 33.7 
处置净利得(9.7)(8.5)
来自港口和铁路运输能力分配的非现金收入(0.3)(9.4)
提前偿还债务产生的净损失— 8.8 
股权联营公司损益（收益）7.1 (9.7)
Shoal Creek 保险赔偿 (16.6)— 
外币期权合约(0.4)(0.1)
流动资产和负债的变化: 
应收账款82.0 126.6 
存货(92.6)(59.9)
其他流动资产15.6 30.1 
应付账款和应计费用(198.3)(29.2)
担保安排143.3 (145.9)
资产养老责任(1.2)3.9 
工人赔偿债务(2.0)(1.3)
养老福利义务(45.0)(46.3)
养老金责任— 0.9 
其他，净数(5.7)(0.1)
净现金流入491.4 832.7 
已终止经营活动的净现金流量(4.7)(79.6)
经营活动产生的净现金流量486.7 753.1 



4

目录


未经审计的现金流量表续 -
截至9月30日的九个月
20242023
(金额单位：百万美元)
投资活动产生的现金流量
物业、厂房、设备及矿山开发的增加(265.7)(190.4)
与资本支出相关的应计费用变动(6.5)(5.1)
Wards Well收购(143.8)— 
保险赔款归因于Shoal Creek设备损失10.9 — 
资产处置收益，减收款16.1 13.9 
对合资企业的出资(550.1)(573.4)
合资企业分配549.8 579.4 
其他，净数(0.3)1.0 
投资活动中使用的净现金(389.6)(174.6)
筹资活动现金流量
长期负债还款(7.2)(6.9)
支付债券发行及其他递延融资费用(11.1)(0.3)
10 (183.1)(264.0)
回购员工普通股，用于代扣税款(4.1)(13.7)
分红派息(28.5)(20.7)
对非控股权益的分配(34.8)(58.9)
融资活动所使用的净现金(268.8)(364.5)
经营性现金流净额(171.7)214.0 
期初现金、现金等价物和受限制的现金(1)
1,650.2 1,417.6 
期末现金、现金等价物和受限制的现金(2)
$1,478.5 $1,631.6 
(1) 以下表格提供了“期初现金、现金等价物和受限现金”的调解
现金及现金等价物$969.3 
受限现金包括在“受限现金和抵押品”中680.9 
期初现金、现金等价物及受限制的现金余额$1,650.2 
(2) 以下表格提供了“期末现金、现金等价物和受限现金”的调解
现金及现金等价物$772.9 
受限现金包括在“受限现金和抵押品”中705.6 
期末现金、现金等价物和受限制现金$1,478.5 
See accompanying notes to unaudited condensed consolidated financial statements.

5

目录


未经审计的简明合并股东权益变动表

截至9月30日的三个月截至9月30日的九个月
2024202320242023
 （金额单位：百万美元，每股数据除外）
普通股
期初余额$1.9 $1.9 $1.9 $1.9 
期末余额1.9 1.9 1.9 1.9 
追加实收资本
期初余额3,987.2 3,979.4 3,983.0 3,975.9 
已宣布的分红派息的分红等价单位0.1 0.1 0.2 0.2 
基于股份的股权分类奖励补偿1.6 1.7 5.7 5.1 
期末余额3,988.9 3,981.2 3,988.9 3,981.2 
自家保管的股票
期初余额(1,825.5)(1,572.4)(1,740.2)(1,372.9)
10 (100.0)(91.0)(183.1)(264.0)
未结算普通股回购的净变化— 8.6 2.6 (2.6)
因普通股回购而计提的消费税(1.0)(0.9)(1.7)(2.5)
为税款扣留而回购员工普通股— — (4.1)(13.7)
期末余额(1,926.5)(1,655.7)(1,926.5)(1,655.7)
留存收益
期初余额1,332.5 820.7 1,112.7 383.9 
归属于普通股股东的净利润101.3 119.9 340.3 567.6 
已宣布的分红派息（$0.075, $0.075, $0.225 and $0.150 每股84,646美元和2,089,185美元
(9.5)(10.0)(28.7)(20.9)
期末余额1,424.3 930.6 1,424.3 930.6 
累计其他综合收益
期初余额161.7 215.1 189.6 242.5 
养老金计划（净额为$0.0 每期税款准备金（税款净额在每期）
(13.3)(13.5)(39.8)(40.3)
外币兑换调整2.3 (1.0)0.9 (1.6)
期末余额150.7 200.6 150.7 200.6 
非控制权益
期初余额57.2 78.6 60.5 63.5 
归属于非控股权益的净收入10.2 11.4 25.4 49.3 
对非控股权益的分配(16.3)(36.1)(34.8)(58.9)
期末余额51.1 53.9 51.1 53.9 
股东权益总额$3,690.4 $3,512.5 $3,690.4 $3,512.5 
请参见附注的未经审计的简明合并财务报表。

6

目录


未经审计的缩编合并财务报表附注
(1)    报告前提
未经审计的简明综合财务报表包括Peabody Energy Corporation（PEC）及其合并子公司和联属公司的账户（连同PEC、公司或Peabody）。由公司控制的子公司的权益与外部股东的权益合并，未经审计的简明综合财务报表的各适用行项目中，除非公司在合营公司中拥有不可分割的权益。在这些情况下，公司在未经审计的简明综合财务报表中的各适用行项目内纳入合营实体的资产、负债、营业收入和费用中的比例份额。所有公司间交易、利润和余额已在合并中予以消除。
附带的未经审计的简明合并基本报表是根据美国普遍接受的会计原则（U.S. GAAP）为中期财务信息而准备的，并遵循10-Q表格的说明和S-X条例第10条。因此，它们不包括U.S. GAAP对完整基本报表所要求的所有信息和附注，并应与公司截至2023年12月31日的10-K年报中包含的合并基本报表及其附注一起阅读。在管理层看来，这些基本报表反映了公平呈现所需的所有正常、经常性调整。本文所呈现的2023年12月31日的资产负债表信息来源于公司截至该日期的经审计合并资产负债表。公司截至2024年9月30日的三个月和九个月的经营结果不一定能反映未来季度或截至2024年12月31日的全年可能预期的结果。
(2)    新采用的会计准则和尚未实施的会计准则
新采纳的会计准则
公司没有采用任何对其未经审计的简明合并基本报表或披露产生重大影响的新会计标准。
尚未实施的会计准则
板块。 2023年11月，发布了ASU 2023-07，要求公共实体在中间期间提供有关报告板块利润或损失的所有披露，这些披露目前每年都要求；披露可从定期提供给首席运营决策者（CODM）的管理报告中轻松计算的重要费用类别和金额；披露CODM如何使用每个报告的指标来分配资源；披露被确定为CODM的个人的姓名和职位头衔。公司必须在2023年12月15日后开始的财政年度和2024年12月15日后开始的财政年度内的中期期间采纳修订。允许提前采用。公司预计这个ASU只会影响其披露，不会影响其合并业绩、现金流量和财务状况。
所得税在2023年12月，发布了ASU 2023-09号，要求公共实体披露更多与所得税率调解和所支付所得税主要相关的信息。该指引还取消了某些现有的披露要求，涉及不确定的税务立场和未承认的递延所得税负债。公司需要在2024年12月15日后开始的财政年度采纳这些修订。修订应该前瞻性应用，可以选择回顾性。允许提前采纳。公司预计这项ASU只会影响其披露，对其合并经营成果、现金流量和财务状况没有影响。
(3)    营业收入确认
请参考公司截至2023年12月31日的10-K年度报告中的第1条注释“重要会计政策摘要”，了解公司关于“营业收入”和“应收账款净额”的政策。

7

目录
未经审计的简明综合财务报表附注（续）
订阅和支持收入包括以下内容（以百万美元为单位）：
按产品类型和市场划分的营业收入见下表。 关于其海上报告部门，公司将根据价格基本类似于出口合同的合同，将国内交付的煤某些收入分类为“出口”。
截至2024年9月30日的三个月
海运热能海运冶金粉河盆地其他美国热
公司及其他(1)
合并
(金额单位：百万美元)
动力煤
国内$38.8 $— $304.2 $214.0 $— $557.0 
272.4 — — — — 272.4 
总动力煤311.2 — 304.2 214.0 — 829.4 
冶金煤
— 240.4 — — — 240.4 
总冶金煤— 240.4 — — — 240.4 
其他 (2)
2.0 2.1 1.1 2.7 10.3 18.2 
收入$313.2 $242.5 $305.3 $216.7 $10.3 $1,088.0 
2023年9月30日结束的九个月中，我们的业务收入为605.39亿美元，比2022年9月30日结束的九个月的577.94亿美元增加了2.745亿美元，增长了4.8%。按恒定汇率计算，营业收入增长了4.8%。2023年9月30日结束的九个月中，我们约有41.7%，47.5%和10.8%的营业收入来自于美国，欧洲和其他地区。在2023年9月30日结束的九个月中，我们的营业收入中有26.7%或527.3亿美元来自于前五大客户。不断有新的客户账户加入我们的大型制药客户、中型制药客户和生物技术客户组合中。
海运热能海运冶金粉河盆地其他美国热
公司及其他(1)
合并
(金额单位：百万美元)
动力煤
国内$31.3 $— $313.3 $227.1 $— $571.7 
265.9 — — — — 265.9 
总动力297.2 — 313.3 227.1 — 837.6 
冶金煤
— 246.0 — — — 246.0 
总冶金— 246.0 — — — 246.0 
其他 (2)
0.2 1.0 (0.3)1.1 (6.7)(4.7)
收入$297.4 $247.0 $313.0 $228.2 $(6.7)$1,078.9 
截至2024年9月30日的九个月
海运热能海运冶金粉河盆地其他美国热
公司及其他(1)
合并
(金额单位：百万美元)
动力煤
国内$116.3 $— $779.7 $592.3 $— $1,488.3 
786.1 — — — — 786.1 
总动力902.4 — 779.7 592.3 — 2,274.4 
冶金煤
— 778.4 — — — 778.4 
总冶金— 778.4 — — — 778.4 
其他 (2)
2.2 5.4 1.6 18.0 33.6 60.8 
收入$904.6 $783.8 $781.3 $610.3 $33.6 $3,113.6 

8

目录
未经审计的简明综合财务报表附注（续）
2023年9月30日结束的三个月中，我们的营业收入为205.51亿美元，比2022年9月30日结束的三个月的194.24亿美元增加了1.127亿美元，增长了5.8%。按恒定汇率计算，营业收入增长了4.8%。2023年9月30日结束的三个月中，我们约有41.7%，47.5%和10.8%的营业收入来自于美国，欧洲和其他地区。在2023年9月30日结束的三个月中，我们的营业收入中有26.7%或527.3亿美元来自于前五大客户。不断有新的客户账户加入我们的大型制药客户、中型制药客户和生物技术客户组合中。这次营业收入增长是由于公司市场的持续有机增长所致。
海运热能海运冶金粉河盆地其他美国热
公司及其他(1)
合并
(金额单位：百万美元)
动力煤
国内$100.7 $— $878.1 $673.2 $— $1,652.0 
942.2 — — — — 942.2 
总动力煤1,042.9 — 878.1 673.2 — 2,594.2 
冶金煤
— 904.8 — — — 904.8 
总冶金煤— 904.8 — — — 904.8 
其他 (2)
0.5 3.1 (0.1)4.3 204.9 212.7 
收入$1,043.4 $907.9 $878.0 $677.5 $204.9 $3,711.7 
(1)    企业和其他包括以下内容：
截至9月30日的三个月截至9月30日的九个月
2024202320242023
(金额单位：百万美元)
与预测销售相关的衍生合同未实现收益$— $— $— $159.0 
与预测销售相关的衍生合同已实现损失— — — (80.9)
煤的实际销售收入 (3)
5.9 (10.4)20.1 97.4 
交易收益— (0.1)— — 
其他 (2)
4.4 3.8 13.5 29.4 
公司及其他总计$10.3 $(6.7)$33.6 $204.9 
(2)    包括与成交量短缺相关的客户合同支付、与煤矿租赁协议相关的特许权使用费、销售代理佣金、农场收入、财产和设施租赁以及与公司转让其多余港口和铁路运力相关的营业收入。
(3)    包括在公司运营部门购入的煤的实际销售时确认的营业收入，并通过公司的煤贸易业务销售给客户，包括作为某些衍生合同结算的一部分。主要代表与客户约定的价格与分配给运营部门的价格之间的差额。
应收账款
2024年9月30日和2023年12月31日的应收账款净额包括以下内容：
2024年9月30日2023年12月31日
 (金额单位：百万美元)
交易应收账款净额$245.9 $322.3 
其他应收款，净额58.3 67.4 
应收账款，净额$304.2 $389.7 
无 上述应收款项中包含截至2024年9月30日或2023年12月31日的信用损失准备金。 No 在截至2024年或2023年9月30日的三个月和九个月期间，确认了信用损失费用。

9

目录
未经审计的简明综合财务报表附注（续）
(4)     存货
2024年9月30日和2023年12月31日的“存货净额”包括以下内容：
2024年9月30日2023年12月31日
 (金额单位：百万美元)
材料和供应，净值$171.2 $153.0 
原煤116.4 105.6 
可销售煤156.7 93.2 
净存货$444.3 $351.8 
上述材料和供应库存净额已显示为减去$的储备后净额5.1 百万美元和美元7.2 百万。
(5) 股权法投资
公司的股权法下投资包括其对Middlemount煤有限公司（Middlemount）、R3可再生能源有限责任公司（R3）和其他一些股权法下投资的利益。
下表总结了这些投资的账面价值，这些投资在简明综合资产负债表的"投资及其他资产"中报告，并列有相关的"股权联营企业的损失（收入）"。
来自权益联营公司的损失（收入）
账面价值为截至9月30日的三个月截至9月30日的九个月
2024年9月30日2023年12月31日2024202320242023
(金额单位：百万美元)
与中山相关的权益法投资$47.3 $42.5 $(2.2)$(8.2)$(4.1)$(14.9)
与R3相关的权益法投资6.6 7.1 4.3 2.6 11.2 5.2 
权益法投资总额$53.9 $49.6 $2.1 $(5.6)$7.1 $(9.7)
R3
结合所得税净变化的前期项目和计量项目六个月截至2024年6月30日的AOCI变化如下（以千美元为单位）：10.8 百万美元和美元5.5 于2024年和2023年截至9月30日的九个月内，分别为R3增长了百万。
(6) 衍生工具与公允价值计量
衍生品
公司会不时利用各种衍生工具来在正常业务过程中管理风险敞口，包括（1）外币汇率风险和与在澳洲矿业平台进行的澳币支出预测相关的现金流量的变动，以及（2）与预测的煤炭销售或购买或固定价格实物销售合同的公允价值变动相关的煤价风险。这些风险管理活动会被积极监督，以确保符合公司的风险管理政策。
在有限的基础上，公司参与煤及货运相关合同的直接交易和经纪交易。除非公司选择对其应用正常采购和正常销售例外，否则所有衍生煤交易合同按公允价值计算。

10

目录
未经审计的简明综合财务报表附注（续）
外币
公司利用期权和套利策略来对冲与预期的澳币运营支出相关的货币风险。截至2024年9月30日，公司持有平均利率期权，名义金额合计$531.0 百万澳币，用于对冲预期的澳币运营支出在截至2025年6月30日的九个月期间内的货币风险。这些工具使公司有权收取对名义金额的付款，如果每季度的澳币对美元的平均汇率超过$0.70 至$0.74 ，在截至2025年6月30日的九个月期间内。截至2024年9月30日，公司还持有购入套利策略，名义金额合计$468.0百万澳币，用于对冲截至2025年6月30日的九个月期间内的预期澳币运营支出。购入套利策略设有约为$0.60 and $0.73和$分别的下限和上限，公司将在低于下限的利率上面临损失，在高于上限的利率上则获利。
与预测销售相关的衍生合约
截至2024年9月30日，公司在吸引计划下有 没有 煤衍生合同涉及其预测销售。历史上，这类金融合同包括期货和远期合同。
金融交易合同
公司可能以有限的力量参与煤炭或货运衍生合约进行交易。这些金融合约可能包括期货、远期和期权。截至2024年9月30日，公司持有名义金融交易合约。
表格衍生品披露
公司与某些对手方签订了主净结协议，允许在违约或终止情况下将资产头寸的合同与负债头寸的合同结算。此类净结安排减少了公司与这些对手方相关的信用风险。为了分类目的，公司将与特定对手方的所有头寸的净公允价值记录在简明合并资产负债表中作为净资产或负债。截至2024年9月30日和2023年12月31日，公司拥有外汇期权合同的资产衍生品，分别价值$6.4 百万美元和美元6.2 百万。资产衍生品的净额包含在附表简明合并资产负债表中的“其他流动资产”中。

11

目录
未经审计的简明综合财务报表附注（续）
目前，公司不寻求对其衍生金融工具进行现金流量套期会计处理，因此公允价值变动体现在当前收益中。 下表显示了公司衍生工具相关的税前收益和损失金额及其在附表中未经审计的简明综合收益表中的分类。
截至2024年9月30日的三个月
在收入中确认的总收益在收入中实现的衍生品损失在收入中确认的衍生品未实现收益
衍生工具分类
(金额单位：百万美元)
外币期权合约运营成本和费用$3.6 $(0.1)$3.7 
总计$3.6 $(0.1)$3.7 
2023年9月30日结束的九个月中，我们的业务收入为605.39亿美元，比2022年9月30日结束的九个月的577.94亿美元增加了2.745亿美元，增长了4.8%。按恒定汇率计算，营业收入增长了4.8%。2023年9月30日结束的九个月中，我们约有41.7%，47.5%和10.8%的营业收入来自于美国，欧洲和其他地区。在2023年9月30日结束的九个月中，我们的营业收入中有26.7%或527.3亿美元来自于前五大客户。不断有新的客户账户加入我们的大型制药客户、中型制药客户和生物技术客户组合中。
确认在收入中的总损失在衍生品上确认的损失在衍生品上确认的未实现（损失）收益
衍生工具分类
(金额单位：百万美元)
外币期权合约运营成本和费用$(2.7)$(2.2)$(0.5)
金融交易合约收入(0.1)(19.7)19.6 
总计$(2.8)$(21.9)$19.1 
截至2024年9月30日的九个月
在收入中确认的总损失在衍生品上实现的损失记入收入在衍生品上确认的未实现收益记入收入
衍生工具分类
(金额单位：百万美元)
外币期权合约运营成本和费用$(2.1)$(2.5)$0.4 
总计$(2.1)$(2.5)$0.4 
2023年9月30日结束的三个月中，我们的营业收入为205.51亿美元，比2022年9月30日结束的三个月的194.24亿美元增加了1.127亿美元，增长了5.8%。按恒定汇率计算，营业收入增长了4.8%。2023年9月30日结束的三个月中，我们约有41.7%，47.5%和10.8%的营业收入来自于美国，欧洲和其他地区。在2023年9月30日结束的三个月中，我们的营业收入中有26.7%或527.3亿美元来自于前五大客户。不断有新的客户账户加入我们的大型制药客户、中型制药客户和生物技术客户组合中。这次营业收入增长是由于公司市场的持续有机增长所致。
在收入中确认的总（损失）收益在收入中确认的衍生品的（损失）收益在收入中确认的衍生品的未实现收益（损失）
衍生工具分类
(金额单位：百万美元)
外币期权合约运营成本和费用$(7.8)$(7.9)$0.1 
与预测销售相关的衍生合同收入78.1 (80.9)159.0 
金融交易合同收入— 11.5 (11.5)
总计$70.3 $(77.3)$147.6 
公司将其衍生工具的现金影响分类在未经审计的简明综合现金流量表的“经营活动现金流量”部分。
公允价值衡量
公司采用三级公允价值层级体系，根据估值中使用的输入的可观察性对公允价值计量的资产和负债进行分类。这些层级包括：第1级 - 输入是活跃市场中同类资产或负债的报价价格；第2级 - 输入是第1级中未列入的其他报价，直接或间接可通过市场确认的输入进行观察；第3级 - 输入是不可观察的，或可观察但无法通过市场确认，需要公司对市场参与者的定价做出假设。

12

目录
未经审计的简明综合财务报表附注（续）
下表列出了公司净资产状况的层级，这些资产的公允价值是按照经常性基础进行测量的。
 2024年9月30日
 一级二级三级总计
 (金额单位：百万美元)
外币期权合约$— $6.4 $— $6.4 
股权证券0.8 — — 0.8 
总净资产$0.8 $6.4 $— $7.2 
 2023年12月31日
 一级二级三级总计
 (金额单位：百万美元)
外币期权合约$— $6.2 $— $6.2 
股权证券0.4 — — 0.4 
总净资产$0.4 $6.2 $— $6.6 
对于1级和2级金融资产和负债，公司采用直接和间接可观察的价格报价，包括利率收益曲线、交易所指数、经纪商/交易商报价、已发布的指数、发行者利差、基准证券和其他市场报价。在某些债务证券的情况下，公允价值由第三方定价服务提供。以下是公司对1级和2级金融资产和负债的估值技术总结：
•外币期权合约的估值是利用在报价公共市场中获得的输入（第2级），除非信用和非履行风险被认为是重要输入，那么公司将此类合约分类为第3级。
•与预测销售和金融交易合同相关的衍生合同通常根据活跃市场中的未调整报价（一级）或通过市场定价确认的估值（二级）进行评估，除非信用和非履约风险被认为是一个重要输入（超过 10的公允价值的%），那么公司将其归类为三级。
•对股权证券的投资基于活跃市场中的未调整报价（第一级）。
其他金融工具公司在2024年9月30日和2023年12月31日估计其他金融工具公平价值时使用了以下方法和假设：
•现金及现金等价物、受限现金、应收账款（包括公司应收账款证券化计划内的账款）、保证金现金、应收票据和应付账款的账面价值接近公允价值，因其短期性或这些工具的流动性质。
•长期债务的公允价值估计基于可用证券的观察价格（第二级），否则基于估算的借款利率将现金流折现至其现值（第三级）。
与公司固定利率长期债务相关的市场风险源于利率上升可能导致公允价值的减少。 下面列出的债务公允价值主要基于报告的市场价值以及基于利率、到期、信用风险、基础抵押品和已完成市场交易的估计。
 2024年9月30日2023年12月31日
 (金额单位：百万美元)
总债务面值$345.1 $342.3 
减：未摊销的债务发行成本(6.6)(8.1)
净资产账面价值$338.5 $334.2 
估计公允价值$501.3 $483.9 
公司的风险管理职能与公司的煤炭交易职能相互独立，负责估值政策和程序，并接受高级管理的监督。公司煤炭衍生资产和负债的公允价值反映了信用风险的调整。公司面临的信用风险主要来自电力公用事业、能源营销商、钢铁生产商和非金融贸易商。

13

目录
未经审计的简明综合财务报表附注（续）
2023年9月30日结束的九个月内，公司持有的三级股权证券投资的实体完成了一笔并购交易，其股份被交换成了新合并实体的股份，该股份已在公开交易。公司在股票交换时记录了一笔减值损失$2.0百万。
公司没有 在截至2024年9月30日和2023年9月30日的三个月和九个月期间，级别1、2和3之间的转移。 公司的政策是使用期初估值来评估所有级别之间的转移。
(7) 物业、厂房、设备及矿山开发
截至2024年9月30日和2023年12月31日的物业、厂房、设备及矿山开发净额的组成如下面表格所示：
2024年9月30日2023年12月31日
(金额单位：百万美元)
土地和煤的利益$2,624.4 $2,475.2 
建筑物和改善658.1 647.6 
机械和设备2,021.4 1,787.6 
减：累计折旧、耗竭和摊销(2,290.4)(2,066.3)
Property, plant, equipment and mine development, net$3,013.5 $2,844.1 
有风险的资产
该公司确定了具有约$的总账面价值的特定资产2072024年9月30日，在其美国其他热力部门中，资产总计约$万美元的资产，其可收回性对客户集中风险最为敏感。
(8)  所得税
截至2024年9月30日的九个月期间，公司在重新测量前的有效税率基于公司估计的全年度有效税率，包括预计的法定税项，减去外部税率差异和估值准备的变动。公司针对2024年和2023年截止至9月30日的收入税项拨备为$25.7 百万美元和美元46.5 $百万的三个月期间的收入税项拨备分别包括$1.0 $百万的税项拨备和$3.3 $百万的税项利益，这些金额与外国所得税账户的重新测量相关。公司针对2024年和2023年截止至9月30日的收入税项拨备为$85.2 百万美元和美元238.7 $百万的九个月期间的收入税项拨备分别包括$税项利益2.9 百万美元和美元2.6 与外币所得税账户的重新计量相关的分别为百万。公司预计全年的税前收入将主要来自澳洲和美国。由于现有的估值拨备，所得税费用主要与澳洲的收入相关。
公司在其所得税准备中确认与未确认税收福利相关的利息和罚款。在截至2024年9月30日的三个月内，没有确认任何罚款或利息。在截至2024年9月30日的九个月内，公司未确认的净税收福利减少了$1.3百万，因而其总利息和罚款减少了$6.1百万，这主要是由于法规的到期。
(9)     长期负债
截至2024年9月30日和2023年12月31日，公司的总债务如下所示:
债务工具（如下定义，如适用）2024年9月30日2023年12月31日
(金额单位：百万美元)
3.250%到期的可转换优先票据（2028年到期的可转换票据）
$320.0 $320.0 
融资租赁义务25.1 22.3 
减：债券发行成本(6.6)(8.1)
338.5 334.2 
减：长期债务的流动部分14.8 13.5 
长期债务$323.7 $320.7 

14

目录
未经审计的简明综合财务报表附注（续）
2028年可转换债券
2022年3月1日，公司通过私人发行发行了总本金金额为美元的2028年可转换票据。320.0百万美元。2028年可转换票据是公司的优先无担保债务，并受信托管理。
公司使用2028年可转换票据发行的收益和可用现金来赎回其当时存在的高级担保票据，并支付与发行和赎回相关的溢价、费用和支出。公司资本化了$11.2 与发行相关的债务发行成本金额为百万美元，这些成本将在票据的期限内摊销。
2028年可转换债券将于2028年3月1日到期，除非根据其条款提前转换、赎回或回购。 3.2502028年可转换债券的年利率为% ，按半年支付，支付时间为每年的3月1日和9月1日。
2028年可转换债券的初始转换率为 50.3816 元公司普通股的1,000 2028年可转换债券的本金金额，代表了大约$的初始转换价格19.85 每股公司普通股的价格。契约条款要求在向公司普通股股东支付分红派息时进行转换率调整，一旦累积分红派息影响转换率至少 1%。自2024年2月21日起，转换率增加至 51.0440 元公司普通股的1,000 2028年可转换债券的本金金额，代表了大约$的调整后转换价格19.59 每股。在适用的转换率公式下，累积$0.150 截至2024年9月30日的六个月内宣布并支付的每股分红派息产生了修订后的转换率 51.3840 每$1,000 2028年可转换票据的本金金额，未达到 1% 51.0440的现有转换率。转换率可能会受到未来的影响，具体取决于累计支付的分红派息。转换率还可能根据契约条款在某些情况下进行进一步调整。
2024年前三季度，公司报告的普通股价格未触发2028年可转换债券的转换条款。因此，2028年可转换债券在2024年第二季度或第三季度期间不可由持有人选择转换，并且在2024年第四季度同样不可转换。
截至2024年9月30日，2028年可转换债券的转换价值超过了本金金额$116.4 百万美元。
循环授信设施
公司与银行签订了一份日期为2024年1月18日的授信协议，设立了一个最高总本金金额为$的新型循环信贷安排。320.0百万的循环承诺，并与公司作为借款人，公司某些附属公司作为协议方，PNC银行，国家协会，作为行政代理以及作为协议方的贷款人，签订了2024年授信协议。公司支付了$的累计债务发行成本。9.7百万。
根据2024年信贷协议设立的循环承诺及任何相关贷款（如适用，统称为循环贷款）将于2028年1月18日终止或到期，具体取决于与公司未偿2028年可转换债券相关的某些条件。循环贷款的利息基于担保隔夜融资利率（SOFR）加上相应的利润空间，范围从 3.50% 到 4.25%，具体取决于公司总净杠杆比率（在2024年信贷协议中定义）或基准利率加上相应的利润空间，范围从 2.50% 到 3.25%，由公司选择。根据2024年信贷协议签发的信用证收取的综合费用等于相应的利润空间，范围从 3.50% 到 4.25%加上每年相当于 0.125%的初始费用。2024年信贷协议下未使用的额度将收取承诺费 0.50年利率为%。
截至2024年9月30日，2024年信贷协议仅用于信用证，包括$98.6截至2024年9月30日，尚未使用的金额为百万美元。这些信用证支持公司的恢复抵押要求、租赁义务、保险政策以及在注释12中进一步说明的其他各类绩效担保。“金融工具和其他担保。”2024年信贷协议下的可用金额为$221.4百万美元于2024年9月30日。

15

目录
未经审计的简明综合财务报表附注（续）
2024年信贷协议包含了一般性契约，这些契约在某些例外情况（包括遵守财务比率）下，可能限制公司及其子公司承担额外的债务、进行某些受限的支付或投资、出售或以其他方式处置资产、与关联方进行交易、创建或承担留置权，以及合并、整合或出售其所有或几乎所有的资产。2024年信贷协议以公司及其美国子公司的几乎所有资产作为担保，并且还对两家澳大利亚子公司进行了质押。
利息成本
下表列出了公司与其债务以及金融担保工具（如保函和信用证）相关的利息费用的元件。 此外，表中列出了支付的现金利息金额，扣除资本化利息，以及主要与债务发行成本摊销相关的非现金利息费用金额。
截至9月30日的三个月截至9月30日的九个月
2024202320242023
 (金额单位：百万美元)
2028年可转换债券$2.6 $2.6 $7.8 $7.8 
融资租赁义务0.4 0.4 1.3 1.4 
金融担保工具5.8 8.9 20.7 28.9 
债务发行成本的摊销0.6 0.7 4.0 2.9 
应收账款证券化项目0.5 0.9 1.9 2.8 
资本化利息(2.7)— (4.4)— 
其他2.5 0.3 3.8 1.7 
利息支出，减去资本化利息$9.7 $13.8 $35.1 $45.5 
支付利息净额，减去已资本化的利息$8.5 $14.8 $32.6 $56.7 
非现金利息费用$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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